EOG RESOURCES INC (Form: 10-Q, Received: 08/06/2013 17:18:27)

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

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

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		272,419,303 (as of July 31, 2013)

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 June 30, 2013 and 2012 and Six Months Ended June 30, 2013 and 2012	3

		Consolidated Balance Sheets - June 30, 2013 and December 31, 2012	4

		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2013 and 2012	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	37

	ITEM 4.	Controls and Procedures	37

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	38

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

	ITEM 4.	Mine Safety Disclosures	38

	ITEM 6.	Exhibits	39

SIGNATURES			41

EXHIBIT INDEX			42

- 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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net Operating Revenues
Crude Oil and Condensate	$	2,012,999		$	1,376,250		$	3,794,832		$	2,686,585
Natural Gas Liquids		178,457			150,023			347,986			348,333
Natural Gas		462,602			359,421			873,481			726,705
Gains on Mark-to-Market Commodity Derivative Contracts		191,490			188,449			86,534			322,657
Gathering, Processing and Marketing		959,413			710,748			1,882,370			1,428,905
Gains on Asset Dispositions, Net		13,153			113,290			177,386			180,758
Other, Net		22,071			11,138			34,110			22,027
Total		3,840,185			2,909,319			7,196,699			5,715,970
Operating Expenses
Lease and Well		268,888			250,756			517,888			512,251
Transportation Costs		224,491			135,393			408,748			267,235
Gathering and Processing Costs		25,897			20,588			50,401			46,180
Exploration Costs		47,323			48,149			91,539			90,956
Dry Hole Costs		35,750			11,081			39,712			11,081
Impairments		37,967			54,217			91,515			187,364
Marketing Costs		965,490			694,118			1,870,139			1,399,586
Depreciation, Depletion and Amortization		910,531			808,765			1,756,919			1,557,508
General and Administrative		80,607			75,727			158,592			151,996
Taxes Other Than Income		151,197			118,186			286,128			239,702
Total		2,748,141			2,216,980			5,271,581			4,463,859
Operating Income		1,092,044			692,339			1,925,118			1,252,111
Other Income (Expense), Net		4,833			4,675			(5,301	)		15,306
Income Before Interest Expense and Income Taxes		1,096,877			697,014			1,919,817			1,267,417
Interest Expense, Net		61,647			50,775			123,568			101,044
Income Before Income Taxes		1,035,230			646,239			1,796,249			1,166,373
Income Tax Provision		375,538			250,461			641,832			446,586
Net Income	$	659,692		$	395,778		$	1,154,417		$	719,787
Net Income Per Share
Basic	$	2.44		$	1.48		$	4.28		$	2.70
Diluted	$	2.42		$	1.47		$	4.24		$	2.67
Dividends Declared per Common Share	$	0.1875		$	0.17		$	0.375		$	0.34
Average Number of Common Shares
Basic		270,016			266,874			269,665			266,718
Diluted		272,739			269,985			272,473			270,083
Comprehensive Income
Net Income	$	659,692		$	395,778		$	1,154,417		$	719,787
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		(19,314	)		(28,689	)		(33,578	)		(2,164	)
Foreign Currency Swap Transaction		(662	)		(1,431	)		1,039			630
Income Tax Related to Foreign Currency Swap Transaction		-			576			-			49
Interest Rate Swap Transaction		584			231			1,321			(364	)
Income Tax Related to Interest Rate Swap Transaction		(210	)		(83	)		(475	)		131
Other		27			31			55			58
Other Comprehensive Income (Loss)		(19,575	)		(29,365	)		(31,638	)		(1,660	)
Comprehensive Income	$	640,117		$	366,413		$	1,122,779		$	718,127

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

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

	June 30,			December 31,
	2013			2012
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,228,016		$	876,435
Accounts Receivable, Net		1,808,954			1,656,618
Inventories		657,400			683,187
Assets from Price Risk Management Activities		105,667			166,135
Income Taxes Receivable		23,450			29,163
Deferred Income Taxes		157,012			-
Other		260,341			178,346
Total		4,240,840			3,589,884

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		40,262,580			38,126,298
Other Property, Plant and Equipment		2,846,971			2,740,619
Total Property, Plant and Equipment		43,109,551			40,866,917
Less: Accumulated Depreciation, Depletion and Amortization		(18,529,163	)		(17,529,236	)
Total Property, Plant and Equipment, Net		24,580,388			23,337,681
Other Assets		255,924			409,013
Total Assets	$	29,077,152		$	27,336,578


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,201,940		$	2,078,948
Accrued Taxes Payable		161,608			162,083
Dividends Payable		50,614			45,802
Liabilities from Price Risk Management Activities		5,482			7,617
Deferred Income Taxes		4,310			22,838
Current Portion of Long-Term Debt		406,579			406,579
Other		189,770			200,191
Total		3,020,303			2,924,058

Long-Term Debt		5,906,210			5,905,602
Other Liabilities		795,308			894,758
Deferred Income Taxes		4,970,705			4,327,396
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 272,611,848 Shares Issued at June 30, 2013 and 271,958,495 Shares Issued at December 31, 2012		202,726			202,720
Additional Paid in Capital		2,576,441			2,500,340
Accumulated Other Comprehensive Income		408,257			439,895
Retained Earnings		11,228,011			10,175,631
Common Stock Held in Treasury, 277,274 Shares at June 30, 2013 and 326,264 Shares at December 31, 2012		(30,809	)		(33,822	)
Total Stockholders' Equity		14,384,626			13,284,764
Total Liabilities and Stockholders' Equity	$	29,077,152		$	27,336,578

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

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

	Six Months Ended
	June 30,
	2013			2012
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	1,154,417		$	719,787
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		1,756,919			1,557,508
Impairments		91,515			187,364
Stock-Based Compensation Expenses		57,724			55,466
Deferred Income Taxes		488,632			278,826
Gains on Asset Dispositions, Net		(177,386	)		(180,758	)
Other, Net		8,747			(3,404	)
Dry Hole Costs		39,712			11,081
Mark-to-Market Commodity Derivative Contracts
Total Gains		(86,534	)		(322,657	)
Realized Gains		135,959			306,780
Excess Tax Benefits from Stock-Based Compensation		(21,869	)		(22,115	)
Other, Net		7,759			9,890
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(164,809	)		115,419
Inventories		22,085			(103,576	)
Accounts Payable		141,369			176,355
Accrued Taxes Payable		24,816			14,363
Other Assets		(92,305	)		(102,303	)
Other Liabilities		(51,400	)		(27,355	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		(19,639	)		(97,453	)
Net Cash Provided by Operating Activities		3,315,712			2,573,218

Investing Cash Flows
Additions to Oil and Gas Properties		(3,250,091	)		(3,748,278	)
Additions to Other Property, Plant and Equipment		(183,516	)		(315,542	)
Proceeds from Sales of Assets		579,941			1,111,517
Changes in Restricted Cash		(52,322	)		-
Changes in Components of Working Capital Associated with Investing Activities		19,358			97,746
Net Cash Used in Investing Activities		(2,886,630	)		(2,854,557	)

Financing Cash Flows
Dividends Paid		(97,006	)		(88,892	)
Excess Tax Benefits from Stock-Based Compensation		21,869			22,115
Treasury Stock Purchased		(21,094	)		(22,663	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		20,773			32,986
Repayment of Capital Lease Obligation		(2,866	)		-
Other, Net		281			(293	)
Net Cash Used in Financing Activities		(78,043	)		(56,747	)

Effect of Exchange Rate Changes on Cash		542			2,734

Increase (Decrease) in Cash and Cash Equivalents		351,581			(335,352	)
Cash and Cash Equivalents at Beginning of Period		876,435			615,726
Cash and Cash Equivalents at End of Period	$	1,228,016		$	280,374

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, 2012, filed on February 22, 2013 (EOG's 2012 Annual Report).

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the full year.

Recently Issued Accounting Standards. In February 2013, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2013-02 "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" (ASU 2013-02). ASU 2013-02 amends ASU 2011-05 and requires that entities disclose additional information about amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. Significant amounts reclassified out of AOCI are required to be presented either on the face of the Consolidated Statements of Income and Comprehensive Income or in the notes to the financial statements. The requirements of ASU 2013-02 are effective for fiscal years and interim periods in those years beginning after December 15, 2012. EOG adopted the provisions of ASU 2013-02 effective January 1, 2013. The adoption did not have a material impact on EOG's financial statements. No significant amounts were reclassified out of AOCI during the three and six months ended June 30, 2013.

- 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 2012 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job function of the employees receiving the grants as follows (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012

Lease and Well	$	8.4	$	8.0	$	18.2	$	16.5
Gathering and Processing Costs		0.3		0.3		0.6		0.5
Exploration Costs		6.4		6.3		13.9		12.9
General and Administrative		12.2		12.5		25.0		25.5
Total	$	27.3	$	27.1	$	57.7	$	55.4

At the 2013 Annual Meeting of Stockholders, EOG's stockholders approved the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan). As more fully discussed in the 2008 Plan document, the 2008 Plan, among other things, authorizes an additional 15,500,000 shares of EOG common stock for grant under the 2008 Plan and extends the expiration date of the 2008 Plan to May 2023.

The 2008 Plan provides for grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units, performance units, performance stock and other stock-based awards. At June 30, 2013, approximately 18.7 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 stock option and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of Employee Stock Purchase Plan (ESPP) grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $10.4 million and $10.5 million during the three months ended June 30, 2013 and 2012, respectively, and $20.8 million and $21.3 million during the six months ended June 30, 2013 and 2012, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the six-month periods ended June 30, 2013 and 2012 are as follows:

	Stock Options/SARs						ESPP
	Six Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Weighted Average Fair Value of Grants	$	38.66		$	35.65		$	28.80		$	28.24
Expected Volatility		35.82	%		39.97	%		29.95	%		46.42	%
Risk-Free Interest Rate		0.48	%		0.49	%		0.12	%		0.06	%
Dividend Yield		0.6	%		0.7	%		0.6	%		0.6	%
Expected Life	5.5 yrs			5.5 yrs			0.5 yrs			0.5 yrs

- 7 -

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

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.

The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2013 and 2012 (stock options and SARs in thousands):

	Six Months Ended					Six Months Ended
	June 30, 2013					June 30, 2012
				Weighted					Weighted
	Number of			Average		Number of			Average
	Stock			Grant		Stock			Grant
	Options/SARs			Price		Options/SARs			Price

Outstanding at January 1		6,219		$	85.81		8,374		$	70.01
Granted		31			125.59		46			106.00
Exercised ⁽¹⁾		(969	)		65.62		(920	)		60.34
Forfeited		(56	)		96.03		(82	)		88.85
Outstanding at June 30 ⁽²⁾		5,225		$	89.69		7,418		$	71.23

Vested or Expected to Vest ⁽³⁾		4,997		$	89.33		7,179		$	70.69

Exercisable at June 30 ⁽⁴⁾		2,255		$	79.97		4,379		$	60.20

(1)

The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2013 and 2012 was $62.1 million and $45.4 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.

(2)

The total intrinsic value of stock options/SARs outstanding at June 30, 2013 and 2012 was $219.5 million and $147.8 million, respectively. At June 30, 2013 and 2012, the weighted average remaining contractual life was 4.1 years and 3.4 years, respectively.

(3)

The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2013 and 2012 was $211.7 million and $146.7 million, respectively. At June 30, 2013 and 2012, the weighted average remaining contractual life was 4.1 years and 3.3 years, respectively.

(4)

The total intrinsic value of stock options/SARs exercisable at June 30, 2013 and 2012 was $116.7 million and $134.3 million, respectively. At June 30, 2013 and 2012, the weighted average remaining contractual life was 2.6 years and 2.0 years, respectively.

At June 30, 2013, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $72.8 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $16.6 million for both the three months ended June 30, 2013 and 2012, and $36.3 million and $34.1 million for the six months ended June 30, 2013 and 2012, respectively.

- 8 -

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

The following table sets forth restricted stock and restricted stock units transactions for the six-month periods ended June 30, 2013 and 2012 (shares and units in thousands):

	Six Months Ended					Six Months Ended
	June 30, 2013					June 30, 2012
				Weighted					Weighted
	Number of			Average		Number of			Average
	Shares and			Grant Date		Shares and			Grant Date
	Units			Fair Value		Units			Fair Value

Outstanding at January 1		3,818		$	91.06		4,240		$	82.93
Granted		265			128.50		290			112.08
Released ⁽¹⁾		(293	)		123.64		(490	)		70.97
Forfeited		(54	)		94.39		(75	)		88.78
Outstanding at June 30 ⁽²⁾		3,736		$	91.11		3,965		$	86.42

(1)

The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2013 and 2012 was $35.4 million and $55.7 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)

The total intrinsic value of restricted stock and restricted stock units outstanding at June 30, 2013 and 2012 was $491.9 million and $357.3 million, respectively.

At June 30, 2013, unrecognized compensation expense related to restricted stock and restricted stock units totaled $129.9 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.4 years.

Performance Units and Performance Stock. As more fully discussed in Note 6 to the Consolidated Financial Statements included in EOG's 2012 Annual Report, in September 2012, EOG granted an aggregate of 54,526 performance units and 16,752 shares of performance stock to its executive officers, which units and shares remained outstanding at June 30, 2013. The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation. Stock-based compensation expense related to performance unit and performance stock grants totaled $0.3 million for the three months ended June 30, 2013, and $0.6 million for the six months ended June 30, 2013.

At June 30, 2013, unrecognized compensation expense related to performance units and performance stock totaled $2.3 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 4.2 years.

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

3. Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and six-month periods ended June 30, 2013 and 2012 (in thousands, except per share data):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Numerator for Basic and Diluted Earnings Per Share -
Net Income	$	659,692	$	395,778	$	1,154,417	$	719,787

Denominator for Basic Earnings Per Share -
Weighted Average Shares		270,016		266,874		269,665		266,718
Potential Dilutive Common Shares -
Stock Options/SARs		987		1,428		1,050		1,611
Restricted Stock/Units and Performance Units/Stock		1,736		1,683		1,758		1,754
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares		272,739		269,985		272,473		270,083

Net Income Per Share
Basic	$	2.44	$	1.48	$	4.28	$	2.70
Diluted	$	2.42	$	1.47	$	4.24	$	2.67

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 0.3 million shares for the three months ended June 30, 2013 and 2012, respectively, and 0.1 million and 0.2 million shares for the six months ended June 30, 2013 and 2012, respectively.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the six-month periods ended June 30, 2013 and 2012 (in thousands):

	Six Months Ended
	June 30,
	2013		2012

Interest ⁽¹⁾	$	121,800	$	97,445
Income Taxes, Net of Refunds Received	$	173,411	$	162,125

(1)	Net of capitalized interest of $22 million and $24 million for the six months ended June 30, 2013 and 2012, respectively.

EOG's accrued capital expenditures at June 30, 2013 and 2012 were $724 million and $857 million, respectively.

- 10 -

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

5. Segment Information

Selected financial information by reportable segment is presented below for the three-month and six-month periods ended June 30, 2013 and 2012 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012

Net Operating Revenues
United States	$	3,612,224		$	2,660,452		$	6,644,076		$	5,251,793
Canada		89,140			96,489			272,883			184,559
Trinidad		132,924			146,274			268,272			267,344
Other International ⁽¹⁾		5,897			6,104			11,468			12,274
Total	$	3,840,185		$	2,909,319		$	7,196,699		$	5,715,970

Operating Income (Loss)
United States	$	1,083,643		$	634,927		$	1,774,169		$	1,165,878
Canada		(20,083	)		(14,052	)		51,330			(52,636	)
Trinidad		71,893			92,947			152,788			170,160
Other International ⁽¹⁾		(43,409	)		(21,483	)		(53,169	)		(31,291	)
Total		1,092,044			692,339			1,925,118			1,252,111

Reconciling Items
Other Income (Expense), Net		4,833			4,675			(5,301	)		15,306
Interest Expense, Net		61,647			50,775			123,568			101,044
Income Before Income Taxes	$	1,035,230		$	646,239		$	1,796,249		$	1,166,373

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

Total assets by reportable segment are presented below at June 30, 2013 and December 31, 2012 (in thousands):

	At		At
	June 30,		December 31,
	2013		2012
Total Assets
United States	$	26,072,533	$	24,523,072
Canada		976,093		1,202,031
Trinidad		1,094,649		1,012,727
Other International ⁽¹⁾		933,877		598,748
Total	$	29,077,152	$	27,336,578

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

- 11 -

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

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 six-month periods ended June 30, 2013 and 2012 (in thousands):

	Six Months Ended
	June 30,
	2013			2012

Carrying Amount at Beginning of Period	$	665,944		$	587,084
Liabilities Incurred		24,660			29,799
Liabilities Settled ⁽¹⁾		(31,155	)		(47,920	)
Accretion		17,865			15,316
Revisions		67			52
Foreign Currency Translations		(11,192	)		(871	)
Carrying Amount at End of Period	$	666,189		$	583,460

Current Portion	$	16,949		$	28,496
Noncurrent Portion	$	649,240		$	554,964

(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.

7. Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the six-month period ended June 30, 2013 are presented below (in thousands):

	Six Months Ended
	June 30, 2013

Balance at December 31, 2012	$	49,116
Additions Pending the Determination of Proved Reserves		69,244
Reclassifications to Proved Properties		(55,555	)
Costs Charged to Expense ⁽¹⁾		(29,807	)
Foreign Currency Translations		(619	)
Balance at June 30, 2013	$	32,379

(1)

Includes capitalized exploratory well costs charged to dry hole costs.

At June 30, 2013, all capitalized exploratory well costs had been capitalized for a period of less than one year.

- 12 -

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

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.

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 of its employees in Canada and Trinidad. For the six months ended June 30, 2013 and 2012, EOG's total costs recognized for these pension plans were $20.6 million and $18.8 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 six months ended June 30, 2013 and 2012, EOG utilized commercial paper, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper issuances at June 30, 2013. The average of the borrowings outstanding under the commercial paper program was $21 million during the six months ended June 30, 2013. The weighted average interest rate for commercial paper for the six months ended June 30, 2013 was 0.31%. At June 30, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 (Floating Rate Notes) and $150 million principal amount of 4.75% Subsidiary Debt due 2014 (4.75% Subsidiary Debt) were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt.

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 June 30, 2013, 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 Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin. At June 30, 2013, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.07% and 3.25%, respectively.

Restricted Cash. In May 2013, the Canadian Alberta Energy Regulator (AER) made effective certain regulations affecting the Licensee Liability Rating program which requires well owners to post financial security for well abandonment obligations in amounts set forth by the AER. In order to comply with these requirements, EOG Resources Canada Inc. (EOGRC) established a 160 million Canadian dollar letter of credit facility (maturing May 29, 2018) with Royal Bank of Canada (RBC) as the lender. The letter of credit facility requires EOGRC to deposit cash, in an amount equal to all outstanding letters of credit under such facility, in a cash collateral account at RBC. At June 30, 2013, the balance in this account was 55 million Canadian dollars (52 million United States dollars).

Common Stock. On February 13, 2013, EOG's Board of Directors increased the quarterly cash dividend on the Common Stock from the previous $0.17 per share to $0.1875 per share, effective with the dividend paid on April 30, 2013 to stockholders of record as of April 16, 2013.

- 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 2012 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 June 30, 2013 and December 31, 2012 (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 June 30, 2013
Financial Assets:
Crude Oil Swaps	$	-	$	19	$	-	$	19
Crude Oil Options/Swaptions		-		35		-		35
Natural Gas Options/Swaptions		-		59		-		59

Financial Liabilities:
Crude Oil Options/Swaptions	$	-	$	5	$	-	$	5
Natural Gas Options/Swaptions		-		1		-		1
Foreign Currency Rate Swap		-		43		-		43
Interest Rate Swap		-		2		-		2

At December 31, 2012
Financial Assets:
Crude Oil Swaps	$	-	$	65	$	-	$	65
Crude Oil Options/Swaptions		-		36		-		36
Natural Gas Options/Swaptions		-		65		-		65

Financial Liabilities:
Crude Oil Options/Swaptions	$	-	$	8	$	-	$	8
Natural Gas Options/Swaptions		-		13		-		13
Foreign Currency Rate Swap		-		55		-		55
Interest Rate Swap		-		4		-		4

- 14 -

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

The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract 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. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

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.

Proved oil and gas properties and other assets with a carrying amount of $131 million were written down to their fair value of $93 million, resulting in pretax impairment charges of $38 million for the six months ended June 30, 2013. Included in the $38 million pretax impairment charges is a $3 million impairment of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser 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 June 30, 2013 and December 31, 2012, EOG had outstanding $6,290 million aggregate principal amount of debt, which had estimated fair values of approximately $6,729 million and $7,032 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 2012 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, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. In addition to financial transactions, from time to time EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. 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.

- 15 -

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

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at June 30, 2013, 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)
2013 ⁽¹⁾
January 2013 (closed)		101,000	$	99.29
February 1, 2013 through April 30, 2013 (closed)		109,000		99.17
May 1, 2013 through June 30, 2013 (closed)		101,000		99.29
July 1, 2013 through September 30, 2013		111,000		98.25
October 1, 2013 through December 31, 2013		103,000		98.26

2014 ⁽²⁾
January 1, 2014 through March 31, 2014		85,000	$	96.24
April 1, 2014 through June 30, 2014		75,000	$	96.20

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods. Options covering a notional volume of 8,000 Bbld are exercisable on September 30, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $98.11 per barrel for each month during the period October 1, 2013 through December 31, 2013. Options covering a notional volume of 54,000 Bbld are exercisable on December 31, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 54,000 Bbld at an average price of $98.91 per barrel for each month during the period January 1, 2014 through June 30, 2014.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 75,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 75,000 Bbld at an average price of $96.20 per barrel for each month during the period July 1, 2014 through December 31, 2014.

- 16 -

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

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at June 30, 2013, 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)
2013 ⁽¹⁾
January 1, 2013 through April 30, 2013 (closed)		150,000	$	4.79
May 1, 2013 through July 31, 2013 (closed)		200,000		4.72
August 1, 2013 through October 31, 2013		200,000		4.72
November 1, 2013 through December 31, 2013		150,000		4.79

2014 ⁽²⁾
January 1, 2014 through December 31, 2014		170,000	$	4.54

(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. For the period August 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period. For the period November 1, 2013 through December 31, 2013, 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 during that period.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates. All 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 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 201 4.

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 4.75% Subsidiary Debt issued by one of EOG's Canadian subsidiaries. The foreign currency swap agreement expires on March 15, 2014. EOG accounts for the foreign currency swap transaction using the hedge accounting method. Changes in the fair value of the foreign currency swap do not impact Net Income. The after-tax net impact from the foreign currency swap resulted in a reduction in Other Comprehensive Income (OCI) of $0.7 million and $0.9 million for the three months ended June 30, 2013 and 2012, respectively, and increases in OCI of $1.0 million and $0.7 million for the six months ended June 30, 2013 and 2012, 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 the Floating Rate Notes. The interest rate swap has a notional amount of $350 million and expires on February 3, 2014. EOG accounts for the interest rate swap transaction using the hedge accounting method. Changes in the fair value of the interest rate swap do not impact Net Income. The after-tax net impact from the interest rate swap resulted in an increase in OCI of $0.4 million and $0.1 million for the three months ended June 30, 2013 and 2012, respectively, and an increase of $0.8 million and a reduction of $0.2 million for the six months ended June 30, 2013 and 2012, respectively.

- 17 -

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

The following table sets forth the amounts, on a gross basis, and classification of EOG's outstanding derivative financial instruments at June 30, 2013 and December 31, 2012. 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
		June 30,		December 31,
Description	Location on Balance Sheet	2013		2012

Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities ⁽¹⁾	$	106	$	166
Current portion	Assets from Price Risk Management Activities ⁽¹⁾	$	106	$	166
Noncurrent portion	Other Assets ⁽²⁾	$	7	$	-

Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities ⁽³⁾	$	5	$	8
Noncurrent portion	Other Liabilities ⁽⁴⁾	$	1	$	13

Foreign currency swap -
Current portion	Current Liabilities - Other	$	43	$	-
Noncurrent portion	Other Liabilities	$	-	$	55

Interest rate swap -
Current portion	Current Liabilities - Other	$	2	$	-
Noncurrent portion	Other Liabilities	$	-	$	4

(1)

The current portion of Assets from Price Risk Management Activities consists of gross assets of $163 million, partially offset by gross liabilities of $57 million at June 30, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million at December 31, 2012.

(2)

The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $10 million, partially offset by gross liabilities of $3 million at June 30, 2013.

(3)

The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $62 million, partially offset by gross assets of $57 million at June 30, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million at December 31, 2012.

(4)

The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $4 million, partially offset by gross assets of $3 million at June 30, 2013 and gross liabilities of $13 million at December 31, 2012.

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 those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk.

- 18 -

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

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 June 30, 2013 and December 31, 2012. EOG held collateral of $5 million at June 30, 2013 and $6 million at December 31, 2012. EOG had no collateral posted at both June 30, 2013 and December 31, 2012.

13. Divestitures

During the first six months of 2013, EOG received proceeds of approximately $580 million primarily from the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal, the proposed Pacific Trail Pipelines and approximately 28,500 undeveloped net acres in the Horn River Basin in Canada and from sales of producing properties and acreage in the Upper Gulf Coast region, the Mid-Continent area and the Permian Basin. During the first six months of 2012, EOG received proceeds of approximately $1,112 million from sales of producing properties and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast region and Canada.

- 19 -

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, China and Argentina. 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 to be successful. 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 liquids-rich natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and liquids-rich reservoirs. In 2013, EOG is focused on developing its existing North American crude oil and liquids-rich acreage and testing methods to improve the recovery factor of the oil-in-place in these plays. In addition, EOG continues to evaluate certain potential crude oil and, to a lesser extent, liquids-rich exploration and development prospects. For the first half of 2013, revenues from the sales of crude oil and condensate and natural gas liquids (NGLs) were approximately 83% of total wellhead revenues. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 54% of total company production for the first half of 2013 as compared to 44% for the comparable period in 2012. In North America, crude oil and condensate and NGLs production accounted for approximately 61% of total North American production during the first half of 2013 as compared to 51% for the comparable period in 2012. This liquids growth primarily reflects increased production from the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken. Based on current trends, EOG expects its 2013 crude oil and condensate and NGLs production to continue to increase both in total and as a percentage of total company production as compared to 2012. In 2013, EOG's major producing areas in the United States and Canada are in New Mexico, North Dakota, Texas, Utah, Wyoming and western Canada.

EOG continues to deliver its crude oil to various markets in the United States, including sales points on the Gulf Coast where sales are based upon the premium Light Louisiana Sweet crude oil index. EOG's crude-by-rail facilities provide EOG the ability to direct its crude oil shipments via rail car to the most favorable markets, including the Gulf Coast, Cushing, Oklahoma, and other markets.

In December 2012, EOG's wholly-owned Canadian subsidiary signed a purchase and sale agreement for the sale of its entire interest in the planned Kitimat liquefied natural gas export terminal, the proposed Pacific Trail Pipelines and approximately 28,500 undeveloped net acres in the Horn River Basin. The transaction closed in February 2013 and is subject to customary post-closing adjustments.

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, Block 4(a) and Modified U(b) Block, as well as in the Pelican Field and the EMZ Area, have been developed and are producing natural gas sold to the National Gas Company of Trinidad and Tobago and condensate sold to the Petroleum Company of Trinidad and Tobago. During the first half of 2013, EOG continued its four-well program in the Modified U(a) Block, drilling three development wells and one successful exploratory well. EOG expects to complete all four wells during the second half of 2013 with initial production commencing in the third quarter.

- 20 -

In the United Kingdom, EOG continues to make progress in field development for its East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party-owned Douglas platform, which will be used to process Conwy production, began in the first quarter of 2013. First production from the Conwy field is anticipated in mid-2014. In the second quarter of 2013, costs totaling $24.1 million associated with the Central North Sea Columbus natural gas project were written off. In the Central North Sea Block 21/12b awarded to EOG in 2009, EOG plans to drill an exploratory well in the second half of 2013. EOG will operate this well.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province. In 2012, a monitor well was drilled and one horizontal well was drilled and completed in the Aguada del Chivato Block. EOG completed the monitor well during the first half of 2013 and is currently evaluating these wells. Also, two additional wells are planned for 2013, one in the Cerro Avispa Block and one in the Bajo del Toro Block.

During the first quarter of 2013, EOG successfully recompleted a well in the Sichuan Basin, Sichuan Province, The People's Republic of China. Two additional wells are planned in the fourth quarter of 2013.

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 31% and 32% at June 30, 2013 and December 31, 2012, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. At June 30, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 and $150 million principal amount of 4.75% Subsidiary Debt due 2014 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt.

EOG's total anticipated 2013 capital expenditures are estimated to range from $7.0 billion to $7.2 billion, excluding acquisitions. The majority of 2013 expenditures have been and will be focused on United States crude oil and, to a lesser extent, liquids-rich natural gas drilling activity. EOG expects capital expenditures to be greater than cash flow from operating activities for 2013. EOG's business plan includes selling certain non-core assets in 2013 to cover the anticipated shortfall. In the first half of 2013, EOG achieved this goal by receiving proceeds of approximately $580 million from sales of assets. 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 $2.0 billion senior unsecured 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.

- 21 -

Results of Operations

The following review of operations for the three and six months ended June 30, 2013 and 2012 should be read in conjunction with the consolidated financial statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.

Three Months Ended June 30, 2013 vs. Three Months Ended June 30, 2012

Net Operating Revenues. During the second quarter of 2013, net operating revenues increased $931 million, or 32%, to $3,840 million from $2,909 million for the same period of 2012. 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 second quarter of 2013 increased $768 million, or 41%, to $2,654 million from $1,886 million for the same period of 2012. During the second quarter of 2013, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $191 million compared to $188 million for the same period of 2012. 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 second quarter of 2013 increased $248 million, or 35%, to $959 million from $711 million for the same period of 2012. Gains on asset dispositions, net, for the second quarter of 2013 totaled $13 million.

- 22 -

Wellhead volume and price statistics for the three-month periods ended June 30, 2013 and 2012 were as follows:

	Three Months Ended
	June 30,
	2013		2012

Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States		206.5		150.5
Canada		6.4		6.4
Trinidad		1.4		1.7
Other International ⁽²⁾		0.1		0.1
Total		214.4		158.7

Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	103.73	$	95.80
Canada		89.66		82.78
Trinidad		86.96		88.68
Other International ⁽²⁾		92.28		91.20
Composite		103.19		95.20

Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States		63.7		54.6
Canada		1.0		0.9
Total		64.7		55.5

Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	30.19	$	33.54
Canada		39.49		42.89
Composite		30.33		33.72

Natural Gas Volumes (MMcfd) ⁽¹⁾
United States		928		1,070
Canada		79		96
Trinidad		346		422
Other International ⁽²⁾		8		10
Total		1,361		1,598

Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	3.73	$	2.09
Canada		3.17		2.21
Trinidad		3.82		3.42
Other International ⁽²⁾		6.81		5.64
Composite		3.73		2.47

Crude Oil Equivalent Volumes (MBoed) ⁽⁴⁾
United States		424.8		383.3
Canada		20.6		23.4
Trinidad		59.0		72.0
Other International ⁽²⁾		1.5		1.8
Total		505.9		480.5

Total MMBoe ⁽⁴⁾		46.0		43.7

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

(2)

Other International includes EOG's United Kingdom, China and Argentina 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.

- 23 -

Wellhead crude oil and condensate revenues for the second quarter of 2013 increased $637 million, or 46%, to $2,013 million from $1,376 million for the same period of 2012, due to an increase of 56 MBbld, or 35%, in wellhead crude oil and condensate deliveries ($481 million) and a higher composite average wellhead crude oil and condensate price ($156 million). The increase in deliveries primarily reflects increased production in the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken. EOG's composite average wellhead crude oil and condensate price for the second quarter of 2013 increased 8% to $103.19 per barrel compared to $95.20 per barrel for the same period of 2012.

NGLs revenues for the second quarter of 2013 increased $28 million, or 19%, to $178 million from $150 million for the same period of 2012, due to an increase of 9 MBbld, or 17%, in NGLs deliveries ($48 million), partially offset by a lower composite average natural gas liquids price ($20 million). The increase in deliveries primarily reflects increased volumes in the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken. EOG's composite average NGLs price for the second quarter of 2013 decreased 10% to $30.33 per barrel compared to $33.72 per barrel for the same period of 2012.

Wellhead natural gas revenues for the second quarter of 2013 increased $103 million, or 29%, to $463 million from $359 million for the same period of 2012. The increase was due to a higher composite average wellhead natural gas price ($156 million), partially offset by a decrease in natural gas deliveries ($53 million). EOG's composite average wellhead natural gas price for the second quarter of 2013 increased 51% to $3.73 per thousand cubic feet (Mcf) compared to $2.47 per Mcf for the same period of 2012. Natural gas deliveries for the second quarter of 2013 decreased 237 MMcfd, or 15%, to 1,361 MMcfd from 1,598 MMcfd for the same period of 2012. The decrease was primarily due to lower production in the United States (142 MMcfd), Trinidad (76 MMcfd) and Canada (17 MMcfd). The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2012. The decrease in Canada was primarily due to reduced drilling activity in Alberta and the Horn River Basin area.

During the second quarter of 2013, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $191 million compared to $188 million for the same period of 2012. During the second quarter of 2013, the net cash inflow related to settled crude oil and natural gas derivative contracts was $69 million compared to $173 million for the same period of 2012.

Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering third-party natural gas. Gathering, processing and marketing revenues were primarily related to sales of third-party crude oil and natural gas. Purchases and sales 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 second quarter of 2013, gathering, processing and marketing revenues and marketing costs increased compared to the same period of 2012 primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the second quarter of 2013 decreased $23 million compared to the same period of 2012 due to lower margins on crude oil marketing activities.

- 24 -

Operating and Other Expenses. For the second quarter of 2013, operating expenses of $2,748 million were $531 million higher than the $2,217 million incurred during the second quarter of 2012. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2013 and 2012:

	Three Months Ended
	June 30,
	2013		2012

Lease and Well	$	5.84	$	5.81
Transportation Costs		4.88		3.14
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties		19.23		17.95
Other Property, Plant and Equipment		0.55		0.79
General and Administrative (G&A)		1.75		1.76
Interest Expense, Net		1.34		1.18
Total ⁽¹⁾	$	33.59	$	30.63

(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, G&A and interest expense, net, for the three months ended June 30, 2013, compared to the same period of 2012 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 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 $269 million for the second quarter of 2013 increased $18 million from $251 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($10 million) and Canada ($3 million), increased workover expenditures in the United States ($4 million) and increased lease and well administrative expenses ($2 million) .

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, costs associated with crude-by-rail operations, 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 and fuel costs.

Transportation costs of $224 million for the second quarter of 2013 increased $89 million from $135 million for the same prior year period primarily due to increased transportation costs related to production from the South Texas Eagle Ford ($44 million), the Rocky Mountain area ($30 million) and the Fort Worth Basin Barnett Shale area ($13 million).

- 25 -

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 DD&A group 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, economic factors 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 generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses for the second quarter of 2013 increased $102 million to $911 million from $809 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2013 were $111 million higher than the same prior year period primarily as a result of increased production in the United States ($85 million) and higher unit rates in the United States ($27 million) and Trinidad ($10 million), partially offset by decreased production in Trinidad ($7 million) and Canada ($7 million). Unit rates increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and an increase in production from higher-cost properties.

G&A expenses of $81 million for the second quarter of 2013 increased $5 million compared to the same prior year period primarily due to higher costs associated with supporting expanding operations.

Interest expense, net, of $62 million for the second quarter of 2013 increased $11 million compared to the same prior year period primarily due to a higher average debt balance.

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 $5 million to $26 million for the second quarter of 2013 compared to $21 million for the same prior year period. The increase primarily reflects increased activities in the South Texas Eagle Ford.

Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties and other assets. 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 DD&A group 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 assets held for sale, EOG utilized accepted bids as the basis for determining fair value.

Impairments of $38 million for the second quarter of 2013 were $16 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties in the United States ($17 million) and decreased amortization of unproved property costs in the United States ($5 million), partially offset by increased impairments of proved properties in Argentina ($6 million). EOG recorded impairments of proved properties of $11 million and $21 million for the second quarter of 2013 and 2012, respectively.

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

- 26 -

Taxes other than income for the second quarter of 2013 increased $33 million to $151 million (5.7% of wellhead revenues) compared to $118 million (6.3% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($25 million) primarily as a result of increased wellhead revenues and increased ad valorem/property taxes in the United States ($7 million).

Income tax provision of $376 million for the second quarter of 2013 increased $125 million compared to the same period of 2012 due primarily to higher pretax income. The net effective tax rate for the second quarter of 2013 decreased to 36% from 39% for the same prior year period.

Six Months Ended June 30, 2013 vs. Six Months Ended June 30, 2012

Net Operating Revenues. During the first six months of 2013, net operating revenues increased $1,481 million, or 26%, to $7,197 million from $5,716 million for the same period of 2012. Total wellhead revenues for the first six months of 2013 increased $1,254 million, or 33%, to $5,016 million from $3,762 million for the same period of 2012. During the first six months of 2013, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $87 million compared to net gains of $323 million for the same period of 2012. Gathering, processing and marketing revenues for the first six months of 2013 increased $453 million, or 32%, to $1,882 million from $1,429 million for the same period of 2012. Gains on asset dispositions, net, of $177 million for the first six months of 2013 primarily consist of gains on asset dispositions in Canada and Texas.

- 27 -

Wellhead volume and price statistics for the six-month periods ended June 30, 2013 and 2012 were as follows:

	Six Months Ended
	June 30,
	2013		2012

Crude Oil and Condensate Volumes (MBbld)
United States		192.4		140.7
Canada		7.1		7.0
Trinidad		1.3		1.9
Other International		0.1		0.1
Total		200.9		149.7

Average Crude Oil and Condensate Prices ($/Bbl) ⁽¹⁾
United States	$	105.04	$	98.61
Canada		87.29		86.33
Trinidad		90.36		94.76
Other International		93.56		96.49
Composite		104.31		98.00

Natural Gas Liquids Volumes (MBbld)
United States		61.2		52.4
Canada		0.9		0.9
Total		62.1		53.3

Average Natural Gas Liquids Prices ($/Bbl)
United States	$	30.87	$	38.12
Canada		40.62		46.54
Composite		31.02		38.27

Natural Gas Volumes (MMcfd)
United States		931		1,067
Canada		79		100
Trinidad		349		396
Other International		8		10
Total		1,367		1,573

Average Natural Gas Prices ($/Mcf) ⁽¹⁾
United States	$	3.41	$	2.28
Canada		3.21		2.33
Trinidad		3.86		3.21
Other International		6.78		5.72
Composite		3.53		2.54

Crude Oil Equivalent Volumes (MBoed)
United States		408.8		370.9
Canada		21.2		24.6
Trinidad		59.4		67.9
Other International		1.4		1.8
Total		490.8		465.2

Total MMBoe		88.8		84.7

(1) Excludes the impact of financial commodity derivative instruments.

- 28 -

Wellhead crude oil and condensate revenues for the first six months of 2013 increased $1,108 million, or 41%, to $3,795 million from $2,687 million for the same period of 2012, due to an increase of 51 MBbld, or 34%, in wellhead crude oil and condensate deliveries ($878 million) and a higher composite average wellhead crude oil and condensate price ($230 million). The increase in deliveries primarily reflects increased production from the South Texas Eagle Ford, the Permian Basin and the North Dakota Bakken. EOG's composite average wellhead crude oil and condensate price for the first six months of 2013 increased 6% to $104.31 per barrel compared to $98.00 per barrel for the same period of 2012.

Wellhead natural gas revenues for the first six months of 2013 increased $146 million, or 20%, to $873 million from $727 million for the same period of 2012. The increase was due to a higher composite average wellhead natural gas price ($245 million), partially offset by decreased natural gas deliveries ($98 million). EOG's composite average wellhead natural gas price for the first six months of 2013 increased 39% to $3.53 per Mcf compared to $2.54 per Mcf for the same period of 2012. Natural gas deliveries for the first six months of 2013 decreased 206 MMcfd, or 13%, to 1,367 MMcfd from 1,573 MMcfd for the same period of 2012. The decrease was primarily due to decreased production in the United States (136 MMcfd), Trinidad (47 MMcfd) and Canada (21 MMcfd). The decrease in the United States was primarily attributable to asset sales and reduced natural gas drilling activity. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2012. The decrease in Canada was due to reduced drilling activity in Alberta and the Horn River Basin area.

During the first six months of 2013, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $87 million compared to $323 million for the same period of 2012. During the first six months of 2013, the net cash inflow related to settled crude oil and natural gas derivative contracts was $136 million compared to $307 million for the same period of 2012.

During the first six months of 2013, gathering, processing and marketing revenues and marketing costs increased compared to the same period of 2012 primarily as a result of increased crude oil marketing activities. Gathering, processing and marketing revenues less marketing costs for the first six months of 2013 decreased $17 million compared to the same period of 2012 due to lower margins on crude oil marketing activities.

Operating and Other Expenses. For the first six months of 2013, operating expenses of $5,272 million were $808 million higher than the $4,464 million incurred during the same period of 2012. The following table presents the costs per Boe for the six-month periods ended June 30, 2013 and 2012:

			Six Months Ended
			June 30,
			2013		2012

Lease and Well		$	5.83	$	6.08
Transportation Costs			4.60		3.17
DD&A -
	Oil and Gas Properties		19.19		17.65
	Other Property, Plant and Equipment		0.58		0.85
G&A			1.79		1.80
Interest Expense, Net			1.39		1.20
	Total ⁽¹⁾	$	33.38	$	30.75

(1)

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

- 29 -

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and interest expense, net, for the six months ended June 30, 2013, compared to the same period of 2012 are set forth below.

Lease and well expenses of $518 million for the first six months of 2013 increased $6 million from $512 million for the same prior year period primarily due to higher lease and well administrative expenses in the United States.

Transportation costs of $409 million for the first six months of 2013 increased $142 million from $267 million for the same prior year period primarily due to increased transportation costs related to production from the South Texas Eagle Ford ($63 million), the Rocky Mountain area ($55 million) and the Fort Worth Basin Barnett Shale area ($21 million).

DD&A expenses for the first six months of 2013 increased $199 million to $1,757 million from $1,558 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2013 were $219 million higher than the same prior year period primarily as a result of increased production in the United States ($132 million) and higher unit rates in the United States ($95 million) and Trinidad ($23 million), partially offset by decreased production in Canada ($16 million) and Trinidad ($8 million) and lower unit rates in Canada ($13 million). Unit rates increased due primarily to downward revisions of natural gas reserves at December 31, 2012, and an increase in production from higher-cost properties.

G&A expenses of $159 million for the first six months of 2013 increased $7 million compared to the same prior year period primarily due to higher costs associated with supporting expanding operations.

Interest expense, net, of $124 million for the first six months of 2013 increased $23 million compared to the same prior year period primarily due to a higher average debt balance ($19 million) and lower capitalized interest ($2 million).

Gathering and processing costs for the first six months of 2013 increased $4 million to $50 million compared to the same prior year period primarily due to increased activities in the South Texas Eagle Ford.

Impairments of $92 million for the first six months of 2013 were $96 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties and other assets in the United States ($96 million) and decreased amortization of unproved property costs in the United States ($17 million), partially offset by increased impairments of proved properties in Canada ($13 million) and Argentina ($6 million). EOG recorded impairments of proved properties and other assets of $38 million and $115 million for the first six months of 2013 and 2012, respectively.

Taxes other than income for the first six months of 2013 increased $46 million to $286 million (5.7% of wellhead revenues) from $240 million (6.4% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($42 million) primarily as a result of increased wellhead revenues, higher ad valorem/property taxes in the United States ($7 million) and a decrease in credits available to EOG in 2013 for Texas high-cost gas severance tax rate reductions ($3 million), partially offset by decreased severance/production taxes in Trinidad ($4 million).

Other income (expense), net for the first six months of 2013 declined $21 million compared to the same prior year period. The decrease was primarily due to an increase in foreign currency transaction losses.

Income tax provision of $642 million for the first six months of 2013 increased $195 million compared to 2012 due primarily to higher pretax income. The net effective tax rate for the first six months of 2013 decreased to 36% from 38% for the same prior year period.

- 30 -

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2013 were funds generated from operations, proceeds from asset sales and proceeds from stock options exercised and employee stock purchase plan activity. The primary uses of cash were funds used in operations; exploration and development expenditures; other property, plant and equipment expenditures; dividend payments to stockholders; and purchases of treasury stock in connection with stock compensation plans. During the first six months of 2013, EOG's cash balance increased $352 million to $1,228 million from $876 million at December 31, 2012.

Net cash provided by operating activities of $3,316 million for the first six months of 2013 increased $742 million compared to the same period of 2012 primarily reflecting an increase in wellhead revenues ($1,254 million), partially offset by an increase in cash operating expenses ($201 million), an unfavorable change in net cash flow from the settlement of financial commodity derivative contracts ($171 million), unfavorable changes in working capital and other assets and liabilities ($125 million), an increase in net cash paid for interest expense ($24 million) and an increase in net cash paid for income taxes ($11 million).

Net cash used in investing activities of $2,887 million for the first six months of 2013 increased by $32 million compared to the same period of 2012 due primarily to a decrease in proceeds from sales of assets ($532 million), unfavorable changes in working capital associated with investing activities ($78 million) and an increase in restricted cash ($52 million), partially offset by a decrease in additions to oil and gas properties ($498 million) and a decrease in additions to other property, plant and equipment ($132 million).

Net cash used in financing activities of $78 million for the first six months of 2013 included cash dividend payments ($97 million) and the purchase of treasury stock in connection with stock compensation plans ($21 million). Cash provided by financing activities for the first six months of 2013 included excess tax benefits from stock-based compensation ($22 million) and proceeds from stock options exercised and employee stock purchase plan activity ($21 million). Net cash used in financing activities of $57 million for the first six months of 2012 included cash dividend payments ($89 million) and purchases of treasury stock in connection with stock compensation plans ($23 million). Cash provided by financing activities for the first six months of 2012 included proceeds from stock options exercised and employee stock purchase plan activity ($33 million) and excess tax benefits from stock-based compensation ($22 million).

Total Expenditures. For the year 2013, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $7.0 billion to $7.2 billion, excluding acquisitions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2013 and 2012 (in millions):

	Six Months Ended
	June 30,
	2013		2012
Expenditure Category
Capital
Drilling and Facilities	$	2,997	$	3,438
Leasehold Acquisitions		188		275
Property Acquisitions		3		-
Capitalized Interest		22		24
Subtotal		3,210		3,737
Exploration Costs		92		91
Dry Hole Costs		40		11
Exploration and Development Expenditures		3,342		3,839
Asset Retirement Costs		27		32
Total Exploration and Development Expenditures		3,369		3,871
Other Property, Plant and Equipment		184		316
Total Expenditures	$	3,553	$	4,187

- 31 -

Exploration and development expenditures of $3,342 million for the first six months of 2013 were $497 million lower than the same period of 2012 due primarily to decreased drilling and facilities expenditures in the United States ($430 million), Canada ($53 million) and Argentina ($23 million); and decreased leasehold acquisition expenditures in the United States ($65 million) and Canada ($21 million). These decreases were partially offset by increased drilling and facilities expenditures in Trinidad ($49 million) and the United Kingdom ($9 million). The exploration and development expenditures for the first six months of 2013 of $3,342 million consist of $2,941 million in development, $376 million in exploration, $22 million in capitalized interest and $3 million in property acquisitions. The exploration and development expenditures for the first six months of 2012 of $3,839 million consist of $3,336 million in development, $479 million in exploration and $24 million in capitalized interest.

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.

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, 2012, filed on February 22, 2013, 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, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounts for financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities. In addition to financial transactions, from time to time EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices.

- 32 -

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 June 30, 2013 as a net asset of $107 million. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at August 6, 2013, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).

Crude Oil Derivative Contracts
			Weighted
	Volume		Average Price
	(Bbld)		($/Bbl)
2013 ⁽¹⁾
January 2013 (closed)		101,000	$	99.29
February 1, 2013 through April 30, 2013 (closed)		109,000		99.17
May 1, 2013 through June 30, 2013 (closed)		101,000		99.29
July 2013 (closed)		111,000		98.25
August 1, 2013 through September 30, 2013		126,000		98.80
October 1, 2013 through December 31, 2013		118,000		98.84

2014 ⁽²⁾
January 1, 2014 through March 31, 2014		103,000	$	96.48
April 1, 2014 through June 30, 2014		93,000		96.47
July 1, 2014 through December 31, 2014		5,000		95.43

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods. Options covering a notional volume of 8,000 Bbld are exercisable on September 30, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $98.11 per barrel for each month during the period October 1, 2013 through December 31, 2013. Options covering a notional volume of 64,000 Bbld are exercisable on December 31, 2013. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 64,000 Bbld at an average price of $99.58 per barrel for each month during the period January 1, 2014 through June 30, 2014.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 93,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 93,000 Bbld at an average price of $96.47 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 5,000 Bbld are exercisable on December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 5,000 Bbld at an average price of $95.43 per barrel for each month during the period January 1, 2015 through June 30, 2015.

- 33 -

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at August 6, 2013, 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)
2013 ⁽¹⁾
January 1, 2013 through April 30, 2013 (closed)		150,000	$	4.79
May 1, 2013 through August 31, 2013 (closed)		200,000		4.72
September 1, 2013 through October 31, 2013		200,000		4.72
November 1, 2013 through December 31, 2013		150,000		4.79

2014 ⁽²⁾
January 1, 2014 through December 31, 2014		170,000	$	4.54

(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. For the period September 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period. For the period November 1, 2013 through December 31, 2013, 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 during that period.

(2)

- 34 -

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, statements regarding future commodity prices 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," "should" 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, unknown or currently unforeseen 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, NGLs, 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;

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, and EOG's ability to retain mineral licenses and leases;

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;

- 35 -

·	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 conditions and developments around the world (such as political instability and armed conflict), 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;

·	physical, electronic and cyber security breaches; and

·	the other factors described under Item 1A, " Risk Factors, " on pages 16 through 23 of EOG's Annual Report on Form 10-K for the year ended December 31, 2012.

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, 2012, filed on February 22, 2013 (EOG's 2012 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 2012 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, "Risk Management Activities," to EOG's 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 furnishes under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the United States 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's share repurchase activity:

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

April 1, 2013 - April 30, 2013	48,588	$	115.86	-	6,386,200
May 1, 2013 - May 31, 2013	25,068		133.96	-	6,386,200
June 1, 2013 - June 30, 2013	8,490		131.83	-	6,386,200
Total	82,146		123.03	-

(1)

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

(2)

In September 2001, the Board authorized the repurchase of up to 10 million shares of EOG's common stock. During the second quarter of 2013, 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.

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ITEM 6. EXHIBITS

Exhibit No. Description

3.1	-	Bylaws, as amended and restated effective as of May 3, 2013 (incorporated by reference to Exhibit 4.2 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.1	-	Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 2, 2013 (incorporated by reference to Exhibit 4.4 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.2	-	Form of Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.5 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.3	-	Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.6 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.4	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.7 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.5	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.8 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.6	-	Form of Performance Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.9 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.7	-	Form of Non-Employee Director Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.10 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.8	-	Form of Non-Employee Director Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.11 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

* 10.9	-	Change of Control Agreement by and between EOG and Lloyd W. Helms, effective as of June 27, 2013.

* 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.

- 39 -

Exhibit No. Description

* **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 June 30, 2013 and 2012 and Six Months Ended June 30, 2013 and 2012, (ii) the Consolidated Balance Sheets - June 30, 2013 and December 31, 2012, (iii) the Consolidated Statements of Cash Flows - Six Months Ended June 30, 2013 and 2012 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: August 6, 2013	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

- 41 -

EXHIBIT INDEX

Exhibit No. Description

3.1	-	Bylaws, as amended and restated effective as of May 3, 2013 (incorporated by reference to Exhibit 4.2 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.1	-	Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 2, 2013 (incorporated by reference to Exhibit 4.4 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.2	-	Form of Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.5 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.3	-	Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.6 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.4	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.7 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.5	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.8 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.6	-	Form of Performance Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.9 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.7	-	Form of Non-Employee Director Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.10 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

10.8	-	Form of Non-Employee Director Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 4.11 to EOG's Registration Statement on Form S-8, filed May 3, 2013).

* 10.9	-	Change of Control Agreement by and between EOG and Lloyd W. Helms, effective as of June 27, 2013.

* 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.

- 42 -

Exhibit No. Description

* **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

EXHIBIT 10.9

CHANGE OF CONTROL AGREEMENT

This Change of Control Agreement ("Agreement") between EOG Resources, Inc., a Delaware corporation (the "Company"), and Lloyd W. Helms (the "Employee") is effective as of this 27 ^th day of June, 2013 (the "Effective Date"). Certain capitalized terms used herein are defined in Section 21.

WITNESSETH:

Whereas, the Company considers it to be in the best interests of its stockholders to encourage the continued employment of certain key employees of the Company notwithstanding the possibility, threat or occurrence of a Change of Control of the Company; and

Whereas, the Employee is a key employee of the Company; and

Whereas, the Company believes that the possibility of the occurrence of a Change of Control of the Company may result in the termination by the Employee of the Employee's employment by the Company or in the distraction of the Employee from the performance of Employee's duties to the Company, in either case to the detriment of the Company and its stockholders; and

Whereas, the Company recognizes that the Employee could suffer adverse financial and professional consequences if a Change of Control of the Company were to occur; and

Whereas, the Company wishes to continue to protect the Employee if a Change of Control of the Company occurs, thereby encouraging the Employee to remain in the employ of the Company and not to be distracted from the performance of Employee's duties to the Company by the possibility of a Change of Control of the Company; and

Now, Therefore, the parties agree as follows:

SECTION 1. OTHER EMPLOYMENT ARRANGEMENTS.

(a) This Agreement does not affect the Employee's existing or future employment arrangements with the Company unless a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement. The Employee's employment with the Company shall continue to be governed by the Employee's existing or future employment agreements with the Company, if any, or, in the absence of any employment agreement, shall continue to be at the will of the Company, except that if a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement and the Employee's employment with the Company is terminated (whether by the Employee or the Company or automatically as provided in Section 3) after the occurrence of that Change of Control of the Company, then the Employee shall be entitled to receive certain benefits as provided in this Agreement.

(b) Nothing in this Agreement shall prevent or limit the Employee's continuing or future participation in any plan, program, policy or practice of or provided by the Company or any of its Affiliates and for which the Employee may qualify, nor shall anything herein limit or otherwise affect such rights as the Employee may have under any contract or agreement with the Company or any of its Affiliates. Amounts which are vested benefits or which the Employee is otherwise entitled to receive under any plan, program, policy or practice of or provided by, or any contract or agreement with, the Company or any of its Affiliates at or subsequent to the date of termination of the Employee's employment with the Company shall be payable or otherwise provided in accordance with such plan, program, policy or practice or contract or agreement except as explicitly modified by this Agreement.

SECTION 2. CHANGE OF CONTROL OF THE COMPANY.

A "Change of Control of the Company" shall mean the occurrence of any of the following events:

(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") (an "Exchange Act Person") of beneficial ownership (within the meaning of Rule 13d‑3 promulgated under the Exchange Act) of 20% or more of either the then-outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or the combined voting power of the then-outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that, for purposes of this clause (a), the following acquisitions shall not constitute a Change of Control of the Company: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any Affiliated Company, (iv) any acquisition by any corporation pursuant to a transaction that complies with subclauses (i), (ii) and (iii) of clause (c) of this Section 2 or (v) an acquisition by a Qualified Institutional Investor, but only for so long as such investor remains a Qualified Institutional Investor;

(b) Individuals who, as of May 3, 2005, constitute the Board of Directors (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board of Directors; provided, however, that any individual becoming a director subsequent to May 3, 2005, whose election, or nomination for election by the Company's stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of an Exchange Act Person other than the Board of Directors;

(c) Consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of the assets or stock of another entity (a "Business Combination"), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities that were the beneficial owners of the Outstanding Company Common Stock and the Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation that, as a result of such transaction, owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Business Combination of the Outstanding Company Common Stock and the Outstanding Company Voting Securities, as the case may be, (ii) no Exchange Act Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then-outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then-outstanding voting securities of such corporation, except to the extent that such ownership existed prior to the Business Combination, and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement or of the action of the Board of Directors providing for such Business Combination; or

(d) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company.

Notwithstanding anything contained in this Agreement to the contrary, if (i) the Employee's employment with the Company is terminated, or (ii) an event occurs which, had it occurred after a Change of Control of the Company, would with proper notice from Employee constitute an Event of Termination for Good Reason, and if it is reasonably demonstrated by the Employee that such action (A) was taken at the request of a third party that has taken steps reasonably calculated to effect a Change of Control of the Company or (B) otherwise arose in connection with or anticipation of a Change of Control of the Company, then for all purposes of this Agreement, such Change of Control of the Company shall be deemed to have occurred on the date immediately prior to the date of such termination or event.

SECTION 3. TERM OF THIS AGREEMENT.

The term of this Agreement shall begin on the Effective Date and shall expire on the first to occur of:

(a) the Employee's death, the Employee's Disability or the Employee's Retirement, which events shall also be deemed automatically to terminate the Employee's employment by the Company; or

(b) the termination by the Employee or the Company of the Employee's employment by the Company.

The expiration of the term of this Agreement shall not terminate this Agreement itself or affect the right of the Employee or the Employee's legal representatives to enforce the payment of any amount or other benefit to which the Employee was entitled before the expiration of the term of this Agreement or to which the Employee became entitled as a result of the event that caused the term of this Agreement to expire.

SECTION 4. EVENT OF TERMINATION FOR CAUSE.

(a) An "Event of Termination for Cause" shall mean the Employee's (i) conviction of a felony involving moral turpitude (which, through lapse of time or otherwise, is not subject to appeal), (ii) willful refusal without proper legal cause to perform employee's duties and responsibilities which remains uncorrected for thirty (30) days following written notice to the Employee by the Company of such event, or (iii) willfully engaging in conduct which the Employee has, or reasonably should have, reason to know is materially injurious to the Company.

(b) For purposes of this Section 4, no act, or failure to act, on the part of the Employee shall be considered "willful" unless it is done, or omitted to be done, by the Employee in bad faith or without reasonable belief that the Employee's action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer of the Company or a senior officer of the Company or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Employee in good faith and in the best interests of the Company.

(c) The cessation of employment of the Employee as a result of the alleged occurrence of an event referred to in clause (ii) or (iii) of the definition of "Event of Termination for Cause" shall not be deemed to be as a result of an Event of Termination for Cause unless and until there shall have been delivered to the Employee a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of Directors (excluding the Employee, if the Employee is a member of the Board of Directors) at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Employee and the Employee is given an opportunity, together with counsel for the Employee, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Employee is guilty of the conduct described in clause (ii) or (iii) of such definition and specifying the particulars thereof in detail. Any determination of the Board of Directors under this clause (c) shall not be binding on the Employee, shall not be conclusive as to whether an Event of Termination for Cause has occurred, and shall not affect Employee's right to contest whether an Event of Termination for Cause has occurred.

SECTION 5. EVENT OF TERMINATION FOR GOOD REASON.

An "Event of Termination for Good Reason" shall mean, after a Change of Control of the Company, the occurrence of any of the following events, provided Employee serves written notice of termination in connection with or based upon any such event within 90 days of the Employee's knowledge of the occurrence of such event:

(a) a reduction in the Employee's authority and/or responsibilities (whether or not occurring solely as a result of the Company's ceasing to be a publicly traded entity); or

(b) a reduction in Employee's Annual Base Salary as in effect immediately prior to the Change of Control of the Company or a reduction in Employee's target annual bonus as in effect immediately prior to the Change of Control of the Company, or the failure to continue the Employee's full participation in any employee benefit plan or program (unless replaced by a substantially comparable plan or program) in which Employee is eligible to participate immediately prior to the Change of Control of the Company (other than as a result of the normal expiration of such plan or program), in each case other than as a part of a general program to reduce compensation or benefits on a proportional basis relative to all other employees of the Company; or

(c) a relocation of the Employee's primary place of work to a location more than 50 miles away from the Employee's primary place of work immediately prior to the Change of Control of the Company (provided, however, this clause (c) shall no longer apply to an employee after he has accepted any such relocation after a Change of Control of the Company has occurred and the above referenced 90 day period has passed), or

(d) the failure of the Company to obtain the assumption in writing of its obligation to perform this Agreement by any successor to the Company prior to a merger, consolidation, sale or similar transaction.

For the avoidance of doubt, any action referred to in clause (a), (b), (c) or (d) above shall constitute an Event of Termination for Good Reason under the foregoing definition regardless of whether the Company is permitted to take such action under any employment contract with the Employee.

SECTION 6. NOTICE OF TERMINATION.

If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement, any termination by the Employee or the Company of the Employee's employment by the Company, or any determination of the Employee's Disability, that occurs within two years of such Change of Control shall be communicated by notice to the other party that shall indicate the specific paragraph of Section 7 pursuant to which the Employee is to receive benefits as a result of the termination. If the notice states that the Employee's employment by the Company has been automatically terminated as a result of the Employee's Disability, the notice shall specifically describe the basis for the determination of the Employee's Disability and shall state the date of the determination of the Employee's Disability, which date shall be not more than ten days before the date such notice is given. If the notice is from the Company and states that the Employee's employment by the Company is terminated by the Company as a result of the occurrence of an Event of Termination for Cause, the notice shall specifically describe the action or inaction of the Employee that the Company believes constitutes an Event of Termination for Cause, and in the case of a termination under clause (ii) or (iii) of the definition of Event of Termination for Cause, shall include the resolution of the Board of Directors referred to in Section 4(c). If the notice is from the Employee and states that the Employee's employment by the Company is terminated by the Employee as a result of the occurrence of an Event of Termination for Good Reason, the notice shall specifically describe the action or inaction of the Company that the Employee believes constitutes an Event of Termination for Good Reason. Each notice given pursuant to this Section 6 (other than a notice stating that the Employee's employment by the Company has been automatically terminated as a result of the Employee's Disability) shall state a date, which shall be not fewer than 30 days nor more than 60 days after the date such notice is given, on which the termination of the Employee's employment by the Company is effective. The date so stated in accordance with this Section 6 shall be the "Termination Date". If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement, any subsequent purported termination by the Company of the Employee's employment by the Company, or any subsequent purported determination by the Company of the Employee's Disability, within two years of such Change of Control shall be ineffective unless that termination or determination shall have been communicated by the Company to the Employee by notice that meets the requirements of the foregoing provisions of this Section 6 and the provisions of Section 9.

SECTION 7. BENEFITS PAYABLE ON CHANGE OF CONTROL AND TERMINATION.

If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement, and the Employee's employment by the Company is terminated (whether by the Employee or the Company or automatically as provided in Section 3) within two years after the occurrence of that Change of Control of the Company, the Employee shall be entitled to the following benefits:

(a) If the Employee's employment by the Company is terminated by the Company as a result of the occurrence of an Event of Termination for Cause, or by the Employee before the occurrence of an Event of Termination for Good Reason, then the Company shall pay to the Employee the Base Salary accrued through the Termination Date but not previously paid to the Employee, and the Employee shall be entitled to any other amounts or benefits provided under any plan, policy, practice, program, contract or arrangement of or with the Company, which shall be governed by the terms thereof (except as explicitly modified by this Agreement).

(b) If the Employee's employment by the Company is automatically terminated as a result of the Employee's death, the Employee's Disability or the Employee's Retirement, then the Company shall pay to the Employee the Base Salary accrued through the date of the occurrence of that event but not previously paid to the Employee, and the Employee shall be entitled to any other amounts or benefits provided under any plan, policy, practice, program, contract or arrangement of or with the Company, which shall be governed by the terms thereof (except as explicitly modified by this Agreement).

(c) If the Employee's employment by the Company is terminated (x) by the Company, other than as a result of the occurrence of an Event of Termination for Cause, or (y) by the Employee after the occurrence of an Event of Termination for Good Reason, then the Employee shall be entitled to the following:

(i) the Company shall pay to the Employee the Base Salary and compensation for earned but unused vacation time accrued through the Termination Date but not previously paid to the Employee;

(ii) the Company shall pay to the Employee, as a lump sum, an amount equal to the total of the following amounts:

(A) 2.99 times the amount of the Employee's Annual Base Salary as in effect immediately prior to the Change of Control (or if increased, immediately prior to the Termination Date); plus

(B) two (2) times the amount of the Employee's target annual bonus as in effect immediately prior to the Change of Control (or if no target annual bonus for the year in which the Change of Control occurs has been set, the target annual bonus for the immediately prior year) (or if increased, immediately prior to the Termination Date); plus

(C) the amount of the Money Purchase Pension Plan contributions that would have been made by the Company on behalf of the Employee if the Employee had continued to be employed by the Company at the Employee's Annual Base Salary as in effect immediately prior to the Change of Control (or if increased, immediately prior to the Termination Date) for three years following the Termination Date; and plus

(D) the amount that would have been paid on behalf of the Employee as matching amounts to the Company's Savings Plan if the Employee had continued to be employed by the Company at the Employee's Annual Base Salary as in effect immediately prior to the Change of Control (or if increased, immediately prior to the Termination Date) for three years following the Termination Date and had continued to contribute to the Company's Savings Plan during such three year period at the Employee's then current contribution level.

(iii) the Company shall arrange for the Employee's uninterrupted participation for three (3) years after the Termination Date in the Company's major medical/dental insurance plan, which participation shall cease upon Employee's eligibility for participation in a major medical/dental insurance plan of another employer;

(iv) the Company shall cause the Employee to receive three (3) years age and service credit for eligibility for the Company's retiree medical insurance coverage; and

(v) the Company shall provide outplacement services at a cost not to exceed $50,000.00.

Each payment required to be made to the Employee pursuant to the foregoing provisions of this Section 7 shall be made by check drawn on an account of the Company at a bank located in the United States of America (unless the Employee has elected to have salary payments deposited directly by the Company to a bank account maintained by the Employee, in which event the Company shall make a direct deposit of the payment to that account), and shall be paid (x) if the Employee's employment by the Company was terminated as a result of the Employee's death, the Employee's Disability or the Employee's Retirement, not more than 30 days immediately following the date of the occurrence of that event, and (y) if the Employee's employment by the Company was terminated for any other reason, not more than ten days immediately following the Termination Date.

SECTION 8. SUCCESSORS.

If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement,

(a) the Company shall not, directly or indirectly, consolidate with, merge into or sell or otherwise transfer its assets as an entirety or substantially as an entirety to, any person, or permit any person to consolidate with or merge into the Company, unless immediately after such consolidation, merger, sale or transfer, the Successor shall have assumed in writing the Company's obligations under this Agreement and agreed to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place; and

(b) not fewer than ten days before the consummation of any consolidation of the Company with, merger by the Company into, or sale or other transfer by the Company of its assets as an entirety or substantially as an entirety to, any person, the Company shall give the Employee notice of that proposed transaction.

SECTION 9. NOTICE.

Notices required or permitted to be given by either party pursuant to this Agreement shall be in writing and shall be deemed to have been given when delivered personally to the other party or when deposited with the United States Postal Service as certified or registered mail with postage prepaid and addressed:

(a) if to the Employee, at the Employee's address last shown on the Company's records, and

(b) if to the Company, at 1111 Bagby, Sky Lobby 2, Houston, Texas 77002, directed to the attention of the Company's Chairman of the Board,

or, in either case, to such other address as the party to whom such notice is to be given shall have specified by notice given to the other party.

SECTION 10. WITHHOLDING TAXES.

The Company may withhold from all payments to be paid to the Employee pursuant to this Agreement all taxes that, by applicable federal or state law, the Company is required to so withhold.

SECTION 11. U.S. EXCISE TAXES.

If any payment or right accruing to the Employee from the Company or an Affiliate under this Agreement without the application of this Section 11 ("Total Payments"), would constitute a "parachute payment" (as defined in Section 280G of the Code (as defined in Section 20) and regulations thereunder), the severance benefit payable under this Agreement shall be reduced to the largest amount that will result in no portion of the amounts payable or rights accruing being subject to an excise tax under Section 4999 of the Code or being disallowed as a deduction under Section 280G of the Code. The determination of whether any reduction in the severance benefit payable is to apply shall be made by a public accounting firm chosen by the Company, at the expense of the Company. Such determination shall be made in good faith after consultation with the Employee and shall be conclusive and binding on the Employee. The Employee shall cooperate in good faith with said accounting firm in making such determination and providing the necessary information for this purpose. The foregoing provisions of this Section 11 shall apply only if after reduction for any applicable federal excise tax imposed by Section 4999 of the Code and federal, state or local income or employment taxes, the Total Payments accruing to the Employee would be less than the amount of the Total Payments as reduced under the foregoing provisions of this Section 11 and after reduction for only federal, state or local income or employment taxes. For the avoidance of doubt, the parties to this Agreement agree that this Section 11 explicitly modifies the U.S. Excise Tax treatment of benefits which may be payable or otherwise provided under any plan, program, policy, or practice of the Company or an Affiliate and any agreement or understanding that the Employee may have with the Company or an Affiliate.

SECTION 12. EXPENSES OF ENFORCEMENT.

The Company agrees to pay as incurred (within ten days following the Company's receipt of an invoice from the Employee), to the full extent permitted by law, all legal fees and expenses that the Employee may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Employee or others of the validity, interpretation or enforceability of, or liability under, any provision of this Agreement (including as a result of any contest by the Employee about the amount of any payment pursuant to this Agreement), plus, in each case, interest on any delayed payment at the applicable federal rate provided for in Section 7872(f)(2)(A) of the Code.

SECTION 13. EMPLOYMENT BY WHOLLY OWNED ENTITIES.

If, at or after the Effective Date, the Employee is or becomes an employee of one or more corporations, partnerships, limited liability companies or other entities that are, directly or indirectly, wholly owned by the Company, references in this Agreement to the Employee's employment by the Company shall include the Employee's employment by any such wholly owned entity.

SECTION 14. NO OBLIGATION TO MITIGATE; NO RIGHTS OF OFFSET.

(a) The Employee shall not be required to mitigate the amount of any payment or other benefit required to be paid to the Employee pursuant to this Agreement, whether by seeking other employment or otherwise, nor shall the amount of any such payment or other benefit be reduced on account of any compensation earned or benefits received by the Employee as a result of employment by another person.

(b) The Company's obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the Employee or others.

SECTION 15. AMENDMENT AND WAIVER.

No provision of this Agreement may be amended or waived (whether by act or course of conduct or omission or otherwise) unless that amendment or waiver is by written instrument signed by the parties hereto. No waiver by either party of any breach of this Agreement shall be deemed a waiver of any other or subsequent breach.

SECTION 16. GOVERNING LAW.

The validity, interpretation, construction and enforceability of this Agreement shall be governed by the laws of the State of Texas.

SECTION 17. VALIDITY.

The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

SECTION 18. COUNTERPARTS.

This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together will constitute the same instrument.

SECTION 19. ASSIGNMENT.

This Agreement shall inure to the benefit of and be enforceable by the Employee's legal representative. The Company may not assign any of its obligations under this Agreement unless (i) such assignment is to a Successor and (ii) the requirements of Section 8 are fulfilled.

SECTION 20. CODE SECTION 409A.

The parties hereto will act in good faith to equitably restructure any payments and benefits provided for in this Agreement to the extent necessary to comply with Section 409A of the Internal Revenue Code of 1986, as amended (the "Code"). Any such restructuring shall not reduce the value of such benefits and payments. Upon the Employee's termination of employment with the Company, in no event shall any payment or provision of benefits be made prior to the date that is six months after the Employee's termination of employment to the extent such payment delay is required under Section 409A(a)(2)(B)(i) of the Code. For purposes of any payments or provision of benefits under this Agreement, the Employee shall not be considered to have terminated employment unless the Employee incurs a "separation from service" with the Company within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable guidance issued thereunder.

SECTION 21. MISCELLANEOUS.

(a) As used in this Agreement, the following terms and phrases have the indicated meanings:

(i) "Affiliate" and "Affiliates" mean, when used with respect to any entity, individual, or other person, any other entity, individual, or other person which, directly or indirectly, through one or more intermediaries controls, or is controlled by, or is under common control with such entity, individual or person. "Affiliated Company" means any entity that is an Affiliate of the Company.

(ii) "Annual Base Salary" means, at any point in time, the regular rate of wages payable to the Employee, expressed on an annualized basis, including any base salary that has been earned but deferred.

(iii) "Board of Directors" means the Board of Directors of the Company.

(iv) "Change of Control of the Company" has the meaning assigned to that phrase in Section 2.

(v) "Company" has the meaning assigned to that term in the preamble to this Agreement. The term "Company" shall also include any Successor, whether the liability of such Successor under this Agreement is established by contract or occurs by operation of law.

(vi) "Effective Date" has the meaning assigned to that term in the preamble to this Agreement.

(vii) "Employee" has the meaning assigned to such term in the preamble to this Agreement.

(viii) "Employee's Disability" means:

(A) if no Change of Control of the Company shall have occurred before the date of determination, the physical or mental disability of the Employee determined in accordance with the disability policy of the Company at the time in effect and generally applicable to its salaried employees; and

(B) if a Change of Control of the Company shall have occurred before the date of determination, the physical or mental disability of the Employee determined in accordance with the disability policy of the Company in effect immediately before the occurrence of the first Change of Control of the Company and generally applicable to its salaried employees.

(ix) "Employee's Retirement" means (x) if no Change of Control of the Company shall have occurred before the date of the Employee's proposed retirement, the retirement of the Employee in accordance with the retirement policy of the Company at the time in effect and generally applicable to its salaried employees, and (y) if a Change of Control of the Company shall have occurred before the date of the Employee's proposed retirement, the retirement of the Employee from the employ of the Company in accordance with the retirement policy of the Company in effect immediately before the occurrence of the first Change of Control of the Company and generally applicable to its salaried employees.

(x) "Event of Termination for Good Reason" has the meaning assigned to that phrase in Section 5.

(xi) "Event of Termination for Cause" has the meaning assigned to that phrase in Section 4.

(xii) "Expiration Date" has the meaning assigned to that term in Section 3.

(xiii) "Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, limited partnership, limited liability company, trust, unincorporated organization, government, or agency or political subdivision of any government.

(xiv) "Qualified Institutional Investor" shall mean, as of any time of determination, a Person that is described in Rule 13d-l(b)(1) promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act") (as such Rule is in effect on the date hereof) and is eligible to report (and, if such Person is the Beneficial Owner of greater than 5% of the shares of common stock of the Company ("Common Shares"), does in fact report) beneficial ownership of Common Shares on Schedule 13G, and such Person (i) is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of Common Shares, and (ii) shall be the Beneficial Owner of less than 15% of the Common Shares then outstanding; provided, however, that a Person which would constitute a Qualified Institutional Investor except for its failure to satisfy clause (ii) of this definition shall nonetheless constitute a Qualified Institutional Investor if (A) such Person or an Affiliate of such Person shall have, as of December 31, 2004, reported beneficial ownership of greater than 5% of the Common Shares for a period of two consecutive years and shall thereafter continuously beneficially own greater than 5% of the Common Shares then outstanding prior to the time of determination, (B) shall be the Beneficial Owner of less than 15% of the Common Shares then outstanding (including in such calculation the holdings of all of such Person's Affiliates and Associates other than those which, under published interpretations of the SEC or its Staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of the Common Shares), and (C) such Person shall be the Beneficial Owner of less than 30% of the Common Shares then outstanding.

Solely for the purposes of the above definition of "Qualified Institutional Investor", a person shall be deemed to be the "Beneficial Owner" of and shall be deemed to "beneficially own" any securities (i) which such Person or any of such Person's Affiliates or Associates (as defined in Rule 12b-2 of the Exchange Act) beneficially owns, directly or indirectly; (ii) which such Person or any of such Person's Affiliates or Associates has (A) the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (other than customary agreements with and between underwriters and selling group members with respect to a bona fide public offering of securities), or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, securities tendered pursuant to a tender or exchange offer made by or on behalf of such Person or any of such Person's Affiliates or Associates until such tendered securities are accepted for purchase or exchange; or (B) the right to vote pursuant to any agreement, arrangement or understanding; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, any security if the agreement, arrangement or understanding to vote such security (1) arises solely from a revocable proxy or consent given to such Person in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable rules and regulations promulgated under the Exchange Act and (2) is not also then reportable on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) which are beneficially owned, directly or indirectly, by any other Person with which such Person or any of such Person's Affiliates or Associates has any agreement, arrangement or understanding (other than customary agreements with and between underwriters and selling group members with respect to a bona fide public offering of securities) for the purpose of acquiring, holding, voting (except to the extent contemplated by the proviso to (ii)(B) above) or disposing of any securities of the Company.

(xv) "Successor" means a person with or into which the Company shall have been merged or consolidated or to which the Company shall have transferred its assets as an entirety or substantially as an entirety.

(xvi) "Termination Date" has the meaning assigned to that term in Section 6.

(xvii) "This Agreement" means this Change of Control Agreement as it may be amended from time to time.

(b) In the event of the enactment of any successor provision to any statute or rule cited in this Agreement, references in this Agreement to such statute or rule shall be to such successor provision.

(d) References in this Agreement to any Section are to the corresponding Section of this Agreement unless the context otherwise indicates.

In Witness Whereof, the Company and the Employee have executed this Agreement as of the Effective Date.

EOG RESOURCES, INC.

By: /s/ PATRICIA L. EDWARDS

Name: Patricia L. Edwards

Title: Vice President, Human Resources and Administration

LLOYD W. HELMS

/s/ L. W. HELMS, JR.