EOG Resources - 10-Q quarterly report FY

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

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 ý 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 ý 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 ý 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 ý

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		547,455,514 (as of July 29, 2014)

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, 2014 and 2013 and Six Months Ended June 30, 2014 and 2013	3

		Consolidated Balance Sheets - June 30, 2014 and December 31, 2013	4

		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2014 and 2013	5

		Notes to Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	35

	ITEM 4.	Controls and Procedures	35

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	36

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

	ITEM 4.	Mine Safety Disclosures	36

	ITEM 6.	Exhibits	37

SIGNATURES			38

EXHIBIT INDEX			39

-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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net Operating Revenues
Crude Oil and Condensate	$	2,618,975		$	2,012,999		$	5,016,077		$	3,794,832
Natural Gas Liquids	247,973			178,457			494,208			347,986
Natural Gas	509,091			462,602			1,065,784			873,481
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	(229,270		)	191,490			(385,006		)	86,534
Gathering, Processing and Marketing	1,027,795			959,413			2,043,206			1,882,370
Gains on Asset Dispositions, Net	3,856			13,153			15,354			177,386
Other, Net	9,136			22,071			21,604			34,110
Total	4,187,556			3,840,185			8,271,227			7,196,699
Operating Expenses
Lease and Well	346,458			268,888			667,292			517,888
Transportation Costs	240,579			224,491			483,816			408,748
Gathering and Processing Costs	32,470			25,897			66,394			50,401
Exploration Costs	42,208			47,323			90,266			91,539
Dry Hole Costs	5,558			35,750			13,906			39,712
Impairments	39,035			37,967			152,396			91,515
Marketing Costs	1,043,515			965,490			2,049,819			1,870,139
Depreciation, Depletion and Amortization	996,602			910,531			1,943,093			1,756,919
General and Administrative	90,932			80,607			173,794			158,592
Taxes Other Than Income	205,469			151,197			401,442			286,128
Total	3,042,826			2,748,141			6,042,218			5,271,581
Operating Income	1,144,730			1,092,044			2,229,009			1,925,118
Other Income (Expense), Net	7,950			4,833			4,612			(5,301		)
Income Before Interest Expense and Income Taxes	1,152,680			1,096,877			2,233,621			1,919,817
Interest Expense, Net	51,867			61,647			102,019			123,568
Income Before Income Taxes	1,100,813			1,035,230			2,131,602			1,796,249
Income Tax Provision	394,460			375,538			764,321			641,832
Net Income	$	706,353		$	659,692		$	1,367,281		$	1,154,417
Net Income Per Share
Basic	$	1.30		$	1.22		$	2.52		$	2.14
Diluted	$	1.29		$	1.21		$	2.49		$	2.12
Dividends Declared per Common Share	$	0.1250		$	0.0938		$	0.2500		$	0.1875
Average Number of Common Shares
Basic	543,099			540,033			542,675			539,330
Diluted	548,676			545,477			548,046			544,946
Comprehensive Income
Net Income	$	706,353		$	659,692		$	1,367,281		$	1,154,417
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	24,378			(19,314		)	11,448			(33,578		)
Foreign Currency Swap Transaction	—			(662		)	50			1,039
Income Tax Related to Foreign Currency Swap Transaction	—			—			(670		)	—
Interest Rate Swap Transaction	—			584			777			1,321
Income Tax Related to Interest Rate Swap Transaction	—			(210		)	(281		)	(475		)
Other	(593		)	27			(570		)	55
Other Comprehensive Income (Loss)	23,785			(19,575		)	10,754			(31,638		)
Comprehensive Income	$	730,138		$	640,117		$	1,378,035		$	1,122,779

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

-3-

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)



	June 30, 2014			December 31, 2013
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,230,140		$	1,318,209
Accounts Receivable, Net	1,902,248			1,658,853
Inventories	667,108			563,268
Assets from Price Risk Management Activities	—			8,260
Income Taxes Receivable	24,527			4,797
Deferred Income Taxes	485,507			244,606
Other	415,215			274,022
Total	4,724,745			4,072,015
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	46,270,734			42,821,803
Other Property, Plant and Equipment	3,374,278			2,967,085
Total Property, Plant and Equipment	49,645,012			45,788,888
Less: Accumulated Depreciation, Depletion and Amortization	(21,449,581		)	(19,640,052		)
Total Property, Plant and Equipment, Net	28,195,431			26,148,836
Other Assets	382,258			353,387
Total Assets	$	33,302,434		$	30,574,238
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,661,473		$	2,254,418
Accrued Taxes Payable	228,569			159,365
Dividends Payable	67,865			50,795
Liabilities from Price Risk Management Activities	338,318			127,542
Current Portion of Long-Term Debt	6,579			6,579
Other	234,683			263,017
Total	3,537,487			2,861,716

Long-Term Debt	5,903,099			5,906,642
Other Liabilities	991,450			865,067
Deferred Income Taxes	6,162,010			5,522,354
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 547,951,875 Shares Issued at June 30, 2014 and 546,378,440 Shares Issued at December 31, 2013	205,482			202,732
Additional Paid in Capital	2,728,482			2,646,879
Accumulated Other Comprehensive Income	426,588			415,834
Retained Earnings	13,398,901			12,168,277
Common Stock Held in Treasury, 515,079 Shares at June 30, 2014 and 206,830 Shares at December 31, 2013	(51,065		)	(15,263		)
Total Stockholders' Equity	16,708,388			15,418,459
Total Liabilities and Stockholders' Equity	$	33,302,434		$	30,574,238

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

-4-

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)



	Six Months Ended June 30,
	2014			2013
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	1,367,281		$	1,154,417
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	1,943,093			1,756,919
Impairments	152,396			91,515
Stock-Based Compensation Expenses	65,144			57,724
Deferred Income Taxes	479,109			488,632
Gains on Asset Dispositions, Net	(15,354		)	(177,386		)
Other, Net	984			8,747
Dry Hole Costs	13,906			39,712
Mark-to-Market Commodity Derivative Contracts
Total Losses (Gains)	385,006			(86,534		)
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts	(120,900		)	135,959
Excess Tax Benefits from Stock-Based Compensation	(63,759		)	(21,869		)
Other, Net	7,223			7,759
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(249,336		)	(164,809		)
Inventories	(109,756		)	22,085
Accounts Payable	347,539			141,369
Accrued Taxes Payable	115,668			24,816
Other Assets	(141,453		)	(92,305		)
Other Liabilities	57,101			(51,400		)
Changes in Components of Working Capital Associated with Investing and Financing Activities	(31,644		)	(19,639		)
Net Cash Provided by Operating Activities	4,202,248			3,315,712
Investing Cash Flows
Additions to Oil and Gas Properties	(3,724,486		)	(3,250,091		)
Additions to Other Property, Plant and Equipment	(402,972		)	(183,516		)
Proceeds from Sales of Assets	74,512			579,941
Changes in Restricted Cash	(91,238		)	(52,322		)
Changes in Components of Working Capital Associated with Investing Activities	31,620			19,358
Net Cash Used in Investing Activities	(4,112,564		)	(2,886,630		)
Financing Cash Flows
Long-Term Debt Borrowings	496,220			—
Long-Term Debt Repayments	(500,000		)	—
Settlement of Foreign Currency Swap	(31,573		)	—
Dividends Paid	(119,684		)	(97,006		)
Excess Tax Benefits from Stock-Based Compensation	63,759			21,869
Treasury Stock Purchased	(89,524		)	(21,094		)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	10,433			20,773
Debt Issuance Costs	(895		)	—
Repayment of Capital Lease Obligation	(2,958		)	(2,866		)
Other, Net	24			281
Net Cash Used in Financing Activities	(174,198		)	(78,043		)
Effect of Exchange Rate Changes on Cash	(3,555		)	542
(Decrease) Increase in Cash and Cash Equivalents	(88,069		)	351,581
Cash and Cash Equivalents at Beginning of Period	1,318,209			876,435
Cash and Cash Equivalents at End of Period	$	1,230,140		$	1,228,016

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, 2013, filed on February 24, 2014 (EOG's 2013 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, 2014, are not necessarily indicative of the results to be expected for the full year.

On February 24, 2014, EOG's Board of Directors (Board) approved a two-for-one stock split in the form of a stock dividend, payable to stockholders of record as of March 17, 2014, and paid on March 31, 2014. All share and per share amounts in the financial statements and these notes have been restated to reflect the two-for-one stock split.

Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09 (ASU 2014-09), "Revenue From Contracts With Customers," which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 will be effective for interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted. EOG is analyzing the requirements of ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

-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 2013 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 June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Lease and Well	$	9.1	$	8.4	$	20.7	$	18.2
Gathering and Processing Costs	0.2		0.3		0.5		0.6
Exploration Costs	5.6		6.4		13.5		13.9
General and Administrative	14.6		12.2		30.4		25.0
Total	$	29.5	$	27.3	$	65.1	$	57.7

The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (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, 2014, approximately 32.3 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 $11.7 million and $10.4 million during the three months ended June 30, 2014 and 2013, respectively, and $23.7 million and $20.8 million during the six months ended June 30, 2014 and 2013, 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, 2014 and 2013 are as follows:



	Stock Options/SARs						ESPP
	Six Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Weighted Average Fair Value of Grants	$	27.68		$	19.33		$	18.30		$	14.40
Expected Volatility	35.15		%	35.82		%	25.83		%	29.95		%
Risk-Free Interest Rate	0.86		%	0.48		%	0.09		%	0.12		%
Dividend Yield	0.5		%	0.6		%	0.4		%	0.6		%
Expected Life	5.2 years			5.5 years			0.5 years			0.5 years

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

-7-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2014 and 2013 (stock options and SARs in thousands):



	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
	Number of Stock Options/SARs		Weighted Average Grant Price		Number of Stock Options/SARs		Weighted Average Grant Price
Outstanding at January 1	10,452		$	54.43	12,438		$	42.91
Granted	74		92.51		62		62.80
Exercised ⁽¹⁾	(922	)	43.76		(1,938	)	32.81
Forfeited	(185	)	62.02		(112	)	48.02
Outstanding at June 30 ⁽²⁾	9,419		$	55.62	10,450		$	44.85
Vested or Expected to Vest ⁽³⁾	8,985		$	55.22	9,994		$	44.67
Exercisable at June 30 ⁽⁴⁾	3,898		$	44.71	4,510		$	39.99


(1)	The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2014 and 2013 was $52.5 million and $62.1 million, respectively. The intrinsic value is based upon the difference between the market price of EOG's common stock on the date of exercise and the grant price of the stock options/SARs.


(2)	The total intrinsic value of stock options/SARs outstanding at June 30, 2014 and 2013 was $576.8 million and $219.5 million, respectively. At June 30, 2014 and 2013, the weighted average remaining contractual life was 4.2 years and 4.1 years, respectively.


(3)	The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2014 and 2013 was $553.8 million and $211.7 million, respectively. At June 30, 2014 and 2013, the weighted average remaining contractual life was 4.2 years and 4.1 years, respectively.


(4)	The total intrinsic value of stock options/SARs exercisable at June 30, 2014 and 2013 was $281.3 million and $116.7 million, respectively. At June 30, 2014 and 2013, the weighted average remaining contractual life was 2.8 years and 2.6 years, respectively.

At June 30, 2014, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $83.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.2 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 $16.8 million and $16.6 million for the three months ended June 30, 2014 and 2013, respectively, and $39.5 million and $36.3 million for the six months ended June 30, 2014 and 2013, respectively.

-8-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth restricted stock and restricted stock unit transactions for the six-month periods ended June 30, 2014 and 2013 (shares and units in thousands):



	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
	Number of Shares and Units		Weighted Average Grant Date Fair Value		Number of Shares and Units		Weighted Average Grant Date Fair Value
Outstanding at January 1	7,358		$	49.54	7,636		$	45.53
Granted	435		94.73		530		64.25
Released ⁽¹⁾	(1,939	)	36.85		(586	)	61.82
Forfeited	(181	)	58.48		(108	)	47.20
Outstanding at June 30 ⁽²⁾	5,673		$	57.06	7,472		$	45.56


(1)	The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2014 and 2013 was $207.0 million and $35.4 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, 2014 and 2013 was $662.9 million and $491.9 million, respectively.

At June 30, 2014, unrecognized compensation expense related to restricted stock and restricted stock units totaled $148.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 years.

Performance Units and Performance Stock. EOG grants performance units and/or performance stock to its executive officers. 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 $1.0 million and $0.3 million for the three months ended June 30, 2014 and 2013, and $1.9 million and $0.6 million for the six months ended June 30, 2014 and 2013.

The following table sets forth performance unit and performance stock transactions for the six-month periods ended June 30, 2014 and 2013 (shares and units in thousands):



	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
	Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	261	$	82.18	143	$	67.05
Granted	—	—		—	—
Released	—	—		—	—
Forfeited	—	—		—	—
Outstanding at June 30 ⁽¹⁾	261	$	82.18	143	$	67.05


(1)	The total intrinsic value of performance units and performance stock outstanding at June 30, 2014 and 2013 was $30.5 million and $9.4 million, respectively.

At June 30, 2014, unrecognized compensation expense related to performance units and performance stock totaled $4.3 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

-9-

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, 2014 and 2013 (in thousands, except per share data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Numerator for Basic and Diluted Earnings Per Share -
Net Income	$	706,353	$	659,692	$	1,367,281	$	1,154,417
Denominator for Basic Earnings Per Share -
Weighted Average Shares	543,099		540,033		542,675		539,330
Potential Dilutive Common Shares -
Stock Options/SARs	2,759		1,973		2,597		2,100
Restricted Stock/Units and Performance Units/Stock	2,818		3,471		2,774		3,516
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares	548,676		545,477		548,046		544,946
Net Income Per Share
Basic	$	1.30	$	1.22	$	2.52	$	2.14
Diluted	$	1.29	$	1.21	$	2.49	$	2.12

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 6 thousand and 0.2 million shares for the three months ended June 30, 2014 and 2013, respectively, and 0.1 million and 0.2 million shares for the six months ended June 30, 2014 and 2013, 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, 2014 and 2013 (in thousands):



	Six Months Ended June 30,
	2014		2013
Interest ⁽¹⁾	$	102,311	$	121,800
Income Taxes, Net of Refunds Received	$	247,494	$	173,411


(1)	Net of capitalized interest of $28 million and $22 million for the six months ended June 30, 2014 and 2013, respectively.

EOG's accrued capital expenditures at June 30, 2014 and 2013 were $872 million and $724 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, 2014 and 2013 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net Operating Revenues
United States	$	3,971,837		$	3,612,224		$	7,823,902		$	6,644,076
Canada	72,562			89,140			163,136			272,883
Trinidad	138,253			132,924			274,986			268,272
Other International ⁽¹⁾	4,904			5,897			9,203			11,468
Total	$	4,187,556		$	3,840,185		$	8,271,227		$	7,196,699
Operating Income (Loss)
United States	$	1,092,198		$	1,083,643		$	2,133,219		$	1,774,169
Canada	(15,804		)	(20,083		)	(25,842		)	51,330
Trinidad	74,142			71,893			148,457			152,788
Other International ⁽¹⁾	(5,806		)	(43,409		)	(26,825		)	(53,169		)
Total	1,144,730			1,092,044			2,229,009			1,925,118
Reconciling Items
Other Income (Expense), Net	7,950			4,833			4,612			(5,301		)
Interest Expense, Net	51,867			61,647			102,019			123,568
Income Before Income Taxes	$	1,100,813		$	1,035,230		$	2,131,602		$	1,796,249

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

Total assets by reportable segment are presented below at June 30, 2014 and December 31, 2013 (in thousands):



	At June 30, 2014		At December 31, 2013
Total Assets
United States	$	30,428,057	$	27,668,713
Canada	856,065		880,765
Trinidad	1,023,244		986,796
Other International ⁽¹⁾	995,068		1,037,964
Total	$	33,302,434	$	30,574,238

(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, 2014 and 2013 (in thousands):



	Six Months Ended June 30,
	2014			2013
Carrying Amount at Beginning of Period	$	761,898		$	665,944
Liabilities Incurred	54,819			24,660
Liabilities Settled ⁽¹⁾	(25,478		)	(31,155		)
Accretion	23,346			17,865
Revisions	13,859			67
Foreign Currency Translations	2,506			(11,192		)
Carrying Amount at End of Period	$	830,950		$	666,189

Current Portion	$	28,498		$	16,949
Noncurrent Portion	$	802,452		$	649,240


(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, 2014 are presented below (in thousands):



	Six Months Ended
	June 30, 2014

Balance at December 31, 2013	$	9,211
Additions Pending the Determination of Proved Reserves	39,159
Reclassifications to Proved Properties	(12,907		)
Costs Charged to Expense	(3,901		)
Foreign Currency Translations	—
Balance at June 30, 2014	$	31,562

At June 30, 2014, all capitalized exploratory well costs had been capitalized for periods of less than one year.

8. Commitments and Contingencies

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

-12-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9. Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, Canada, Trinidad and the United Kingdom, and defined benefit pension plans covering certain of its employees in Canada and Trinidad. For the six months ended June 30, 2014 and 2013, EOG's total costs recognized for these pension plans were $20.2 million and $20.6 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, 2014 and 2013, EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper or uncommitted credit facilities at June 30, 2014. The average borrowings outstanding under the commercial paper program were $18 million and $21 million during the six months ended June 30, 2014 and 2013, respectively. The average borrowings outstanding under the uncommitted credit facilities were $0.2 million and zero during the six months ended June 30, 2014 and 2013, respectively. The weighted average interest rates for commercial paper borrowings during the six months ended June 30, 2014 and 2013 were 0.25% and 0.31%, respectively, and 0.70% for uncommitted credit facility borrowings during the six months ended June 30, 2014.

On March 21, 2014, EOG closed its sale of the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 (Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2014. Net proceeds from the Notes offering of approximately $496 million were used for general corporate purposes.

On March 17, 2014, EOG repaid upon maturity the $150 million aggregate principal amount of its 4.75% Subsidiary Debt due 2014 (Subsidiary Debt) and settled the foreign currency swap entered into contemporaneously with the issuance of the Subsidiary Debt for $32 million.

On February 3, 2014, EOG repaid upon maturity the $350 million aggregate principal amount of its Floating Rate Senior Notes due 2014 (Floating Rate Notes). On the same date, EOG settled the interest rate swap entered into contemporaneously with the issuance of the Floating Rate Notes for $0.8 million.

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, 2014, 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, 2014, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.03% and 3.25%, respectively.

Restricted Cash. In order to comply with the Canadian Alberta Energy Regulator's requirements to post financial security for well abandonment obligations, EOG Resources Canada Inc. (EOGRC) established a 160 million Canadian dollar letter of credit facility (subsequently increased to 190 million Canadian dollars) which matures on 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, 2014, the balance in this account was 170 million Canadian dollars (159 million United States dollars).

Common Stock. On February 24, 2014, the Board increased the quarterly cash dividend on the common stock from the previous $0.09375 per share to $0.125 per share, effective beginning with the dividend paid on April 30, 2014 to stockholders of record as of April 16, 2014. On August 5, 2014, the Board increased the quarterly cash dividend on the common stock from the previous $0.125 per share to $0.1675 per share, effective beginning with the dividend to be paid on October 31, 2014, to stockholders of record as of October 17, 2014.

-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 2013 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, 2014 and December 31, 2013 (in millions):



	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At June 30, 2014
Financial Assets:
Natural Gas Options/Swaptions	$	—	$	5	$	—	$	5

Financial Liabilities:
Crude Oil Swaps	$	—	$	157	$	—	$	157
Crude Oil Options/Swaptions	—		170		—		170
Natural Gas Options/Swaptions	—		11		—		11

At December 31, 2013
Financial Assets:
Natural Gas Options/Swaptions	$	—	$	8	$	—	$	8

Financial Liabilities:
Crude Oil Swaps	$	—	$	17	$	—	$	17
Crude Oil Options/Swaptions	—		110		—		110
Foreign Currency Rate Swap	—		40		—		40
Interest Rate Swap	—		1		—		1

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 with a carrying amount of $95 million were written down to their fair value of $20 million, resulting in pretax impairment charges of $75 million for the six months ended June 30, 2014. Included in the $75 million pretax impairment charges are $56 million of impairments 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 inputs 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, 2014 and December 31, 2013, EOG had outstanding $5,890 million aggregate principal amount of debt, which had estimated fair values of approximately $6,323 million and $6,222 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.

-14-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12. Risk Management Activities

Commodity Price Risk. As more fully discussed in Note 11 to the Consolidated Financial Statements included in EOG's 2013 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 accounting 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.

Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at June 30, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).



Crude Oil Derivative Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2014
January 2014 (closed)	156,000	$	96.30
February 2014 (closed)	171,000	96.35
March 1, 2014 through June 30, 2014 (closed)	181,000	96.55
July 1, 2014 through August 31, 2014	202,000	96.34
September 1, 2014 through December 31, 2014	192,000	96.15

2015 ⁽¹⁾	—	$	—

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015.

-15-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at June 30, 2014, 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)
2014 ⁽¹⁾
January 2014 (closed)	230,000	$	4.51
February 2014 (closed)	710,000	4.57
March 2014 (closed)	810,000	4.60
April 2014 (closed)	465,000	4.52
May 2014 (closed)	685,000	4.55
June 2014 (closed)	515,000	4.52
July 2014 (closed)	340,000	4.55
August 1, 2014 through December 31, 2014	330,000	4.55

2015 ⁽²⁾
January 1, 2015 through December 31, 2015	175,000	$	4.51

(1)

EOG has entered into natural gas derivative contracts which give counterparties the 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 480,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period August 1, 2014 through December 31, 2014.

(2)

EOG has entered into natural gas derivative contracts which give counterparties the 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 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.

Foreign Currency Exchange Rate Derivative. EOG was party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may have resulted from the Subsidiary Debt issued by one of EOG's Canadian subsidiaries. The foreign currency swap expired and was settled contemporaneously with the repayment upon maturity of the Subsidiary Debt on March 17, 2014 (see Note 10).

Interest Rate Derivative. EOG was 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 its Floating Rate Notes. The interest rate swap expired and was settled contemporaneously with the repayment upon maturity of the Floating Rate Notes on February 3, 2014 (see Note 10).

-16-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at June 30, 2014 and December 31, 2013. 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
Description	Location on Balance Sheet	June 30, 2014		December 31, 2013

Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities ⁽¹⁾	$	—	$	8
Noncurrent portion	Other Assets ⁽²⁾	$	5	$	—

Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities ⁽³⁾	$	338	$	127
Noncurrent portion	Other Liabilities ⁽⁴⁾	$	—	$	—

Foreign currency swap -
Current portion	Current Liabilities - Other	$	—	$	40

Interest rate swap -
Current portion	Current Liabilities - Other	$	—	$	1


(1)	The current portion of Assets from Price Risk Management Activities consists of gross assets of $14 million, offset by gross liabilities of $14 million at June 30, 2014, and gross assets of $18 million, partially offset by gross liabilities of $10 million at December 31, 2013.


(2)	The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $11 million, partially offset by gross liabilities of $6 million at June 30, 2014.


(3)	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $352 million, partially offset by gross assets of $14 million at June 30, 2014, and gross liabilities of $137 million, partially offset by gross assets of $10 million at December 31, 2013.


(4)	The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $6 million, offset by gross assets of $6 million at June 30, 2014.

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 renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk.

All of EOG's outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings 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 were in a net liability position at June 30, 2014 and December 31, 2013. EOG held no collateral at June 30, 2014 and December 31, 2013. EOG had collateral of $79 million posted at June 30, 2014 and no collateral posted at December 31, 2013.

-17-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

13. Divestitures

During the first six months of 2014, EOG received proceeds of approximately $75 million from sales of producing properties and acreage primarily in the Mid-Continent area, the Upper Gulf Coast region, Canada and the Rocky Mountain area. During the first six months of 2013, EOG received proceeds of approximately $580 million primarily from sales of its entire interest in the planned Kitimat project, undeveloped acreage in the Horn River Basin in Canada and producing properties and acreage in the Upper Gulf Coast region, the Mid-Continent area and the Permian Basin.

-18-

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 emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves, 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. 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 have contributed substantially to, and are expected to continue 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 2014, EOG remains focused on developing its existing North American crude oil and liquids-rich acreage. In addition, increasing drilling and completion efficiencies and testing methods to improve the recovery factor of oil-in-place remain areas of emphasis in 2014. EOG also continues to evaluate certain potential crude oil and, to a lesser extent, liquids-rich exploration and development prospects. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids (NGLs) to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 68% of total North American production during the first half of 2014 as compared to 61% for the comparable period in 2013. This liquids growth primarily reflects increased production from the South Texas Eagle Ford, the North Dakota Bakken and the Permian Basin. Based on current trends, EOG expects its 2014 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 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.

International. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a) and Modified U(b) Block and the EMZ Area have been developed and are producing natural gas sold to the National Gas Company of Trinidad and Tobago and crude oil and condensate sold to the Petroleum Company of Trinidad and Tobago. EOG expects to drill three net development wells in the SECC and Modified U(b) Blocks during 2014.

In the United Kingdom, EOG continues to make progress in the development of its 100% working interest East Irish Sea Conwy crude oil discovery. Modifications to the nearby third-party-owned Douglas platform, which will be used to process Conwy production, continued in the first half of 2014. First production from the Conwy field is anticipated in early 2015.

EOG's activity in Argentina is focused on the Vaca Muerta oil shale formation in the Neuquén Basin in Neuquén Province. In 2014, EOG completed a vertical well in the Cerro Avispa Block that was drilled in late 2013. The well was determined to be a dry hole in the second quarter of 2014. During the second quarter of 2014, EOG began drilling an exploratory well in the Bajo del Toro Block. EOG continues to evaluate its drilling results and exploration program in Argentina.

In the Sichuan Basin, Sichuan Province, People's Republic of China, EOG completed two wells during the first half of 2014 and plans to drill five additional wells on its acreage during the remainder of 2014.

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.

-19-

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 26% and 28% at June 30, 2014 and December 31, 2013, respectively. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

EOG's total anticipated 2014 capital expenditures are estimated to range from $8.1 billion to $8.3 billion, excluding acquisitions. The majority of 2014 expenditures have been, and will continue to be, focused on United States crude oil and, to a lesser extent, liquids-rich drilling activity. 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.

-20-

Results of Operations

The following review of operations for the three and six months ended June 30, 2014 and 2013 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, 2014 vs. Three Months Ended June 30, 2013

Net Operating Revenues. During the second quarter of 2014, net operating revenues increased $348 million, or 9%, to $4,188 million from $3,840 million for the same period of 2013. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the second quarter of 2014 increased $722 million, or 27%, to $3,376 million from $2,654 million for the same period of 2013. During the second quarter of 2014, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $229 million compared to net gains of $191 million for the same period of 2013. Gathering, processing and marketing revenues, which are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas as well as fees associated with gathering third-party natural gas, for the second quarter of 2014 increased $69 million, or 7%, to $1,028 million from $959 million for the same period of 2013. Gains on asset dispositions, net, totaled $4 million and $13 million for the second quarters of 2014 and 2013, respectively.

-21-

Wellhead volume and price statistics for the three-month periods ended June 30, 2014 and 2013 were as follows:



	Three Months Ended June 30,
	2014		2013
Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	274.6		206.5
Canada	5.6		6.4
Trinidad	1.0		1.4
Other International ⁽²⁾	0.1		0.1
Total	281.3		214.4
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	102.66	$	103.73
Canada	94.66		89.66
Trinidad	94.25		86.96
Other International ⁽²⁾	91.27		92.28
Composite	102.47		103.19
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	78.5		63.7
Canada	0.7		1.0
Total	79.2		64.7
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	34.35	$	30.19
Canada	40.90		39.49
Composite	34.41		30.33
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	925		928
Canada	67		79
Trinidad	380		346
Other International ⁽²⁾	11		8
Total	1,383		1,361
Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	4.14	$	3.73
Canada	4.72		3.17
Trinidad	3.69		3.82
Other International ⁽²⁾	4.39		6.81
Composite	4.04		3.73
Crude Oil Equivalent Volumes (MBoed) ⁽⁴⁾
United States	507.2		424.8
Canada	17.4		20.6
Trinidad	64.5		59.0
Other International ⁽²⁾	1.9		1.5
Total	591.0		505.9

Total MMBoe ⁽⁴⁾	53.8		46.0


(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 (see Note 12 to the Consolidated Financial Statements).

(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.

-22-

Wellhead crude oil and condensate revenues for the second quarter of 2014 increased $606 million, or 30%, to $2,619 million from $2,013 million for the same period of 2013 due to an increase of 67 MBbld, or 31%, in wellhead crude oil and condensate production ($625 million) primarily in the Eagle Ford and the North Dakota Bakken, partially offset by a lower composite average wellhead crude oil and condensate price ($19 million). EOG's composite average wellhead crude oil and condensate price for the second quarter of 2014 decreased 1% to $102.47 per barrel compared to $103.19 per barrel for the same period of 2013.

NGLs revenues for the second quarter of 2014 increased $70 million, or 39%, to $248 million from $178 million for the same period of 2013 due to an increase of 15 MBbld, or 22%, in NGLs deliveries ($40 million) and a higher composite average price ($30 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford and the Permian Basin. EOG's composite average NGLs price for the second quarter of 2014 increased 13% to $34.41 per barrel compared to $30.33 per barrel for the same period of 2013.

Wellhead natural gas revenues for the second quarter of 2014 increased $46 million, or 10%, to $509 million from $463 million for the same period of 2013. The increase was due to a higher composite average wellhead natural gas price ($39 million) and an increase in natural gas deliveries ($7 million). Natural gas deliveries for the second quarter of 2014 increased 22 MMcfd, or 2%, to 1,383 MMcfd from 1,361 MMcfd for the same period of 2013 due primarily to increased production in Trinidad (34 MMcfd), partially offset by lower production in Canada (12 MMcfd). The increase in Trinidad was primarily attributable to increased contractual deliveries. The decrease in Canada was primarily due to decreased production in Alberta and the Horn River Basin area. EOG's composite average wellhead natural gas price for the second quarter of 2014 increased 8% to $4.04 per Mcf compared to $3.73 per Mcf for the same period of 2013.

During the second quarter of 2014, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $229 million compared to net gains of $191 million for the same period of 2013. During the second quarter of 2014, the net cash payments for settlements of crude oil and natural gas financial derivative contracts were $87 million compared to net cash received from settlements of crude oil and natural gas financial derivative contracts of $69 million for the same period of 2013.

Gathering, processing and marketing revenues relate to the sale 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.

Gathering, processing and marketing revenues less marketing costs for the second quarter of 2014 declined $10 million as compared to the same period of 2013. The decline primarily reflects lower margins on crude oil marketing activities.

Operating and Other Expenses. For the second quarter of 2014, operating expenses of $3,043 million were $295 million higher than the $2,748 million incurred during the second quarter of 2013. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2014 and 2013:



	Three Months Ended June 30,
	2014		2013
Lease and Well	$	6.45	$	5.84
Transportation Costs	4.48		4.88
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	18.01		19.23
Other Property, Plant and Equipment	0.54		0.55
General and Administrative (G&A)	1.69		1.75
Interest Expense, Net	0.97		1.34
Total ⁽¹⁾	$	32.14	$	33.59


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

-23-

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, 2014, compared to the same period of 2013 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

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.

Lease and well expenses of $346 million for the second quarter of 2014 increased $77 million from $269 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($43 million) and Canada ($7 million), increased workover expenditures ($22 million) and increased lease and well administrative expenses ($7 million) in the United States.

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 $241 million for the second quarter of 2014 increased $17 million from $224 million for the same prior year period primarily due to increased transportation costs related to production from the Eagle Ford ($16 million) and the Rocky Mountain area ($5 million), partially offset by decreased transportation costs related to production from the Fort Worth Basin Barnett Shale area ($3 million) and the Permian Basin ($3 million).

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 period to period. 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 2014 increased $86 million to $997 million from $911 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2014 were $82 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($152 million), partially offset by a decrease in unit rates in the United States ($62 million). Unit rates decreased primarily due to upward reserve revisions.

G&A expenses of $91 million for the second quarter of 2014 increased $10 million compared to the same prior year period primarily due to increased costs associated with supporting expanding operations.

Interest expense, net, of $52 million for the second quarter of 2014 decreased $10 million compared to the same prior year period primarily due to lower composite interest rates on outstanding debt ($6 million) and increased capitalized interest ($2 million).

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

Gathering and processing costs increased $6 million to $32 million for the second quarter of 2014 compared to $26 million for the same prior year period. The increase primarily reflects increased activities in the Eagle Ford.

Exploration costs of $42 million for the second quarter of 2014 decreased $5 million from $47 million for the same prior year period primarily due to decreased geological and geophysical expenditures in the United States.

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Impairments include amortization of unproved oil and gas property costs, as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. 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 expected undiscounted future 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 described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification. In certain instances, EOG utilizes accepted bids as the basis for determining fair value.

Impairments of $39 million for the second quarter of 2014 were $1 million higher than impairments for the same prior year period primarily due to increased amortization of unproved property costs in the United States ($11 million), partially offset by lower impairments of proved properties in Argentina ($6 million) and the United States ($4 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $1 million and $11 million for the second quarter of 2014 and 2013, 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.

Taxes other than income for the second quarter of 2014 increased $54 million to $205 million (6.1% of wellhead revenues) compared to $151 million (5.7% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($45 million) primarily as a result of increased wellhead revenues and increased ad valorem/property taxes in the United States ($11 million).

Income tax provision of $394 million for the second quarter of 2014 increased $18 million from $376 million in the second quarter of 2013 due primarily to higher pretax income. The net effective tax rate for the second quarter of 2014 of 36% was unchanged from the same prior year period.

Six Months Ended June 30, 2014 vs. Six Months Ended June 30, 2013

Net Operating Revenues. During the first six months of 2014, net operating revenues increased $1,074 million, or 15%, to $8,271 million from $7,197 million for the same period of 2013. Total wellhead revenues for the first six months of 2014 increased $1,560 million, or 31%, to $6,576 million from $5,016 million for the same period of 2013. During the first six months of 2014, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $385 million compared to net gains of $87 million for the same period of 2013. Gathering, processing and marketing revenues for the first six months of 2014 increased $161 million, or 9%, to $2,043 million from $1,882 million for the same period of 2013. Gains on asset dispositions, net, totaled $15 million and $177 million for the first six months of 2014 and 2013, respectively.

-25-

Wellhead volume and price statistics for the six-month periods ended June 30, 2014 and 2013 were as follows:



	Six Months Ended June 30,
	2014		2013
Crude Oil and Condensate Volumes (MBbld)
United States	266.4		192.4
Canada	6.4		7.1
Trinidad	1.0		1.3
Other International	0.1		0.1
Total	273.9		200.9
Average Crude Oil and Condensate Prices ($/Bbl) ⁽¹⁾
United States	$	101.66	$	105.04
Canada	92.05		87.29
Trinidad	92.09		90.36
Other International	89.10		93.56
Composite	101.40		104.31
Natural Gas Liquids Volumes (MBbld)
United States	74.7		61.2
Canada	0.7		0.9
Total	75.4		62.1
Average Natural Gas Liquids Prices ($/Bbl)
United States	$	36.12	$	30.87
Canada	44.15		40.62
Composite	36.20		31.02
Natural Gas Volumes (MMcfd)
United States	910		931
Canada	65		79
Trinidad	384		349
Other International	9		8
Total	1,368		1,367
Average Natural Gas Prices ($/Mcf) ⁽¹⁾
United States	$	4.54	$	3.41
Canada	4.71		3.21
Trinidad	3.66		3.86
Other International	5.04		6.78
Composite	4.31		3.53
Crude Oil Equivalent Volumes (MBoed)
United States	492.7		408.8
Canada	18.1		21.2
Trinidad	65.0		59.4
Other International	1.5		1.4
Total	577.3		490.8

Total MMBoe	104.5		88.8

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

-26-

Wellhead crude oil and condensate revenues for the first six months of 2014 increased $1,221 million, or 32%, to $5,016 million from $3,795 million for the same period of 2013 due to an increase of 73 MBbld, or 36%, in wellhead crude oil and condensate production ($1,366 million) primarily in the Eagle Ford and the North Dakota Bakken, partially offset by a lower composite average wellhead crude oil and condensate price ($145 million). EOG's composite average wellhead crude oil and condensate price for the first six months of 2014 decreased 3% to $101.40 per barrel compared to $104.31 per barrel for the same period of 2013.

NGLs revenues for the first six months of 2014 increased $146 million, or 42%, to $494 million from $348 million for the same period of 2013 due to an increase of 13 MBbld, or 21%, in NGLs deliveries ($75 million) and a higher composite average price ($71 million). The increase in deliveries primarily reflects increased volumes in the Eagle Ford and the Permian Basin. EOG's composite average NGLs price for the first six months of 2014 increased 17% to $36.20 per barrel compared to $31.02 per barrel for the same period of 2013.

Wellhead natural gas revenues for the first six months of 2014 increased $193 million, or 22%, to $1,066 million from $873 million for the same period of 2013. The increase was primarily due to a higher composite average wellhead natural gas price ($192 million). Natural gas deliveries for the first six months of 2014 were flat, with production of 1,368 MMcfd compared to 1,367 MMcfd for the same period of 2013. EOG's composite average wellhead natural gas price for the first six months of 2014 increased 22% to $4.31 per Mcf compared to $3.53 per Mcf for the same period of 2013.

During the first six months of 2014, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $385 million compared to net gains of $87 million for the same period of 2013. During the first six months of 2014, the net cash payments for settlements of crude oil and natural gas financial derivative contracts were $121 million compared to net cash received from settlements of crude oil and natural gas financial derivative contracts of $136 million for the same period of 2013.

Gathering, processing and marketing revenues less marketing costs for the first six months of 2014 declined $19 million as compared to the same period of 2013 primarily due to lower margins on crude oil marketing activities.

Operating and Other Expenses. For the first six months of 2014, operating expenses of $6,042 million were $770 million higher than the $5,272 million incurred during the same period of 2013. The following table presents the costs per Boe for the six-month periods ended June 30, 2014 and 2013:



	Six Months Ended June 30,
	2014		2013
Lease and Well	$	6.39	$	5.83
Transportation Costs	4.64		4.60
DD&A -
Oil and Gas Properties	18.08		19.19
Other Property, Plant and Equipment	0.53		0.58
G&A	1.67		1.79
Interest Expense, Net	0.98		1.39
Total ⁽¹⁾	$	32.29	$	33.38


(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 six months ended June 30, 2014, compared to the same period of 2013 are set forth below. See "Net Operating Revenues" above for a discussion of production volumes.

-27-

Lease and well expenses of $667 million for the first six months of 2014 increased $149 million from $518 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($91 million) and Canada ($11 million) and increased workover expenditures ($40 million) and increased lease and well administrative expenses ($9 million) in the United States.

Transportation costs of $484 million for the first six months of 2014 increased $75 million from $409 million for the same prior year period primarily due to increased transportation costs related to production from the Eagle Ford ($60 million) and the Rocky Mountain area ($22 million), partially offset by decreased transportation costs related to production from the Fort Worth Basin Barnett Shale area ($7 million).

DD&A expenses for the first six months of 2014 increased $186 million to $1,943 million from $1,757 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2014 were $183 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($308 million), partially offset by a decrease in unit rates in the United States ($122 million). Unit rates decreased primarily due to upward reserve revisions.

G&A expenses of $174 million for the first six months of 2014 increased $15 million compared to the same prior year period primarily due to increased costs associated with supporting expanding operations.

Interest expense, net, of $102 million for the first six months of 2014 decreased $22 million compared to the same prior year period primarily due to net debt repayments and lower composite interest rates on outstanding debt ($14 million) and increased capitalized interest ($6 million).

Gathering and processing costs for the first six months of 2014 increased $16 million to $66 million compared to the same prior year period primarily due to increased activities in the Eagle Ford.

Impairments of $152 million for the first six months of 2014 were $61 million higher than impairments for the same prior year period primarily due to higher impairments of proved properties in the United States ($49 million) and increased amortization of unproved property costs in the United States ($24 million), partially offset by lower impairments of proved properties in Argentina ($6 million) and Canada ($5 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $75 million and $38 million for the first six months of 2014 and 2013, respectively.

Taxes other than income for the first six months of 2014 increased $115 million to $401 million (6.1% of wellhead revenues) from $286 million (5.7% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States ($96 million) primarily as a result of increased wellhead revenues and higher ad valorem/property taxes in the United States ($19 million).

Other income (expense), net for the first six months of 2014 increased $10 million compared to the same prior year period. The increase was primarily due to an increase in foreign currency transaction gains ($26 million), partially offset by increased deferred compensation expense ($7 million), increased losses on the disposition of warehouse stock and other fixed assets ($6 million) and decreased interest income ($3 million).

Income tax provision of $764 million for the first six months of 2014 increased $122 million from $642 million compared to 2013 due primarily to higher pretax income. The net effective tax rate for the first six months of 2014 of 36% was unchanged from the same prior year period.

-28-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2014 were funds generated from operations, net proceeds from the issuance of the Notes, proceeds from asset sales, excess tax benefits from stock-based compensation 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; repayments of long-term debt; other property, plant and equipment expenditures; dividend payments to stockholders; increase in restricted cash; and purchases of treasury stock in connection with stock compensation plans. During the first six months of 2014, EOG's cash balance decreased $88 million to $1,230 million from $1,318 million at December 31, 2013.

Net cash provided by operating activities of $4,202 million for the first six months of 2014 increased $887 million compared to the same period of 2013 primarily reflecting an increase in wellhead revenues ($1,560 million), favorable changes in working capital and other assets and liabilities ($37 million) and a decrease in net cash paid for interest expense ($19 million), partially offset by an increase in cash operating expenses ($355 million), an unfavorable change in net cash flow from the settlement of financial commodity derivative contracts ($257 million) and an increase in net cash paid for income taxes ($74 million).

Net cash used in investing activities of $4,113 million for the first six months of 2014 increased by $1,226 million compared to the same period of 2013 due primarily to a decrease in proceeds from sales of assets ($505 million); an increase in additions to oil and gas properties ($474 million); an increase in additions to other property, plant and equipment ($219 million); and an increase in restricted cash ($39 million); partially offset by favorable changes in working capital associated with investing activities ($12 million).

Net cash used in financing activities of $174 million for the first six months of 2014 included repayments of long-term debt ($500 million), cash dividend payments ($120 million), purchases of treasury stock in connection with stock compensation plans ($90 million) and the settlement of a foreign currency swap ($32 million). Cash provided by financing activities for the first six months of 2014 included net proceeds from the issuance of the Notes ($496 million), excess tax benefits from stock-based compensation ($64 million) and proceeds from stock options exercised and employee stock purchase plan activity ($10 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).

Total Expenditures. For the year 2014, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $8.1 billion to $8.3 billion, excluding acquisitions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2014 and 2013 (in millions):



	Six Months Ended June 30,
	2014		2013
Expenditure Category
Capital
Drilling and Facilities	$	3,412	$	2,997
Leasehold Acquisitions	196		188
Property Acquisitions	78		3
Capitalized Interest	28		22
Subtotal	3,714		3,210
Exploration Costs	90		92
Dry Hole Costs	14		40
Exploration and Development Expenditures	3,818		3,342
Asset Retirement Costs	69		27
Total Exploration and Development Expenditures	3,887		3,369
Other Property, Plant and Equipment	403		184
Total Expenditures	$	4,290	$	3,553

-29-

Exploration and development expenditures of $3,818 million for the first six months of 2014 were $476 million higher than the same period of 2013 due primarily to increased drilling and facilities expenditures in the United States ($506 million) and China ($7 million) increased property acquisitions in the United States ($75 million) and increased leasehold acquisitions in the United States ($9 million), partially offset by decreased drilling and facilities expenditures in Trinidad ($63 million), Canada ($26 million) and Argentina ($10 million). The exploration and development expenditures for the first six months of 2014 of $3,818 million consist of $3,365 million in development, $347 million in exploration, $78 million in property acquisitions and $28 million in capitalized interest. 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 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, 2013, filed on February 24, 2014, 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 (Losses) 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.

-30-

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, 2014, as a net liability of $333 million. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at August 5, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).



Crude Oil Derivative Contracts
		Weighted Average Price ($/Bbl)
	Volume (Bbld)
	Volume (Bbld)
2014
January 2014 (closed)	156,000		$	96.30
February 2014 (closed)	171,000	96.35
March 1, 2014 through June 30, 2014 (closed)	181,000	96.55
July 2014 (closed)	202,000	96.34
August 2014	202,000	96.34
September 1, 2014 through December 31, 2014	192,000	96.15

2015 ⁽¹⁾	—		$	—

(1)

-31-

Presented below is a comprehensive summary of EOG's natural gas derivative contracts at August 5, 2014, 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
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)
	Volume (MMBtud)
2014 ⁽¹⁾
January 2014 (closed)	230,000		$	4.51
February 2014 (closed)	710,000	4.57
March 2014 (closed)	810,000	4.60
April 2014 (closed)	465,000	4.52
May 2014 (closed)	685,000	4.55
June 2014 (closed)	515,000	4.52
July 2014 (closed)	340,000	4.55
August 2014 (closed)	330,000	4.55
September 1, 2014 through December 31, 2014	330,000	4.55

2015 ⁽²⁾
January 1, 2015 through December 31, 2015	175,000		$	4.51

(1)

(2)

EOG has entered into natural gas derivative contracts which give counterparties the 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 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period January 1, 2015 through December 31, 2015.

-32-

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, natural gas liquids, natural gas and related commodities;


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


•	the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and optimize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;


•	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, appropriate gathering, processing, compression, transportation and refining 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, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;


•	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, facilities, equipment, materials and services;


•	the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) 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 (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;


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


•	EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;


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


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


•	political 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;

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•	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 17 through 26 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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 47 through 51 of EOG's Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 24, 2014 (EOG's 2013 Annual Report); and (ii) Note 11, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-27 through F-30 of EOG's 2013 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:



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

April 1, 2014 - April 30, 2014	26,304	$	100.20	—	6,386,200
May 1, 2014 - May 31, 2014	34,457	102.95		—	6,386,200
June 1, 2014 - June 30, 2014	465,526	116.47		—	6,386,200
Total	526,287	114.77		—

(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 2014, 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

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

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

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

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

* 95	-	Mine Safety Disclosure Exhibit.

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

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

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

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

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

* Exhibits filed herewith

** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income and Comprehensive Income - Three Months Ended June 30, 2014 and 2013 and Six Months Ended June 30, 2014 and 2013, (ii) the Consolidated Balance Sheets - June 30, 2014 and December 31, 2013, (iii) the Consolidated Statements of Cash Flows - Six Months Ended June 30, 2014 and 2013 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 5, 2014	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

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EXHIBIT INDEX



Exhibit No.		Description

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

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

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

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

* 95	-	Mine Safety Disclosure Exhibit.

* **101.INS	-	XBRL Instance Document.

* **101.SCH	-	XBRL Schema Document.

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

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

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

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

* Exhibits filed herewith

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EOG Resources - 10-Q quarterly report FY

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