Edgar Filing: EOG RESOURCES INC

Document

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, 2017

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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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		577,448,119 (as of July 25, 2017)

EOG RESOURCES, INC.

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - Three Months Ended June 30, 2017 and 2016 and Six Months Ended June 30, 2017 and 2016	3

		Condensed Consolidated Balance Sheets - June 30, 2017 and December 31, 2016	4

		Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2017 and 2016	5

		Notes to Condensed 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	38

SIGNATURES			39

EXHIBIT INDEX			40

-2-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EOG RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(In Thousands, Except Per Share Data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net Operating Revenues and Other
Crude Oil and Condensate	$	1,445,454		$	1,059,690		$	2,875,515		$	1,813,401
Natural Gas Liquids	146,907			111,643			300,351			186,962
Natural Gas	224,008			155,983			454,610			321,486
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	9,446			(44,373		)	71,466			(38,938		)
Gathering, Processing and Marketing	778,797			485,256			1,505,334			819,209
Losses on Asset Dispositions, Net	(8,916		)	(15,550		)	(25,674		)	(6,403		)
Other, Net	16,776			23,091			41,435			34,372
Total	2,612,472			1,775,740			5,223,037			3,130,089
Operating Expenses
Lease and Well	255,186			218,393			510,963			459,258
Transportation Costs	186,356			179,471			365,070			369,925
Gathering and Processing Costs	34,746			29,226			72,890			57,750
Exploration Costs	34,711			30,559			91,605			60,388
Dry Hole Costs	27			(172		)	27			74
Impairments	78,934			72,714			272,121			144,331
Marketing Costs	790,599			480,046			1,527,135			820,900
Depreciation, Depletion and Amortization	865,384			862,491			1,681,420			1,791,382
General and Administrative	108,507			97,705			205,745			198,236
Taxes Other Than Income	130,114			93,480			260,407			154,159
Total	2,484,564			2,063,913			4,987,383			4,056,403
Operating Income (Loss)	127,908			(288,173		)	235,654			(926,314		)
Other Income (Expense), Net	4,972			(20,996		)	8,123			(25,433		)
Income (Loss) Before Interest Expense and Income Taxes	132,880			(309,169		)	243,777			(951,747		)
Interest Expense, Net	70,413			71,108			141,928			139,498
Income (Loss) Before Income Taxes	62,467			(380,277		)	101,849			(1,091,245		)
Income Tax Provision (Benefit)	39,414			(87,719		)	50,279			(326,911		)
Net Income (Loss)	$	23,053		$	(292,558	)	$	51,570		$	(764,334	)
Net Income (Loss) Per Share
Basic	$	0.04		$	(0.53	)	$	0.09		$	(1.40	)
Diluted	$	0.04		$	(0.53	)	$	0.09		$	(1.40	)
Dividends Declared per Common Share	$	0.1675		$	0.1675		$	0.3350		$	0.3350
Average Number of Common Shares
Basic	574,439			547,335			574,162			547,029
Diluted	578,483			547,335			578,573			547,029
Comprehensive Income (Loss)
Net Income (Loss)	$	23,053		$	(292,558	)	$	51,570		$	(764,334	)
Other Comprehensive Income
Foreign Currency Translation Adjustments	1,260			5,844			1,569			8,029
Other, Net of Tax	(86		)	23			(49		)	45
Other Comprehensive Income	1,174			5,867			1,520			8,074
Comprehensive Income (Loss)	$	24,227		$	(286,691	)	$	53,090		$	(756,260	)

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

-3-

EOG RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)



	June 30, 2017			December 31, 2016
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,649,443		$	1,599,895
Accounts Receivable, Net	1,114,454			1,216,320
Inventories	336,198			350,017
Assets from Price Risk Management Activities	4,746			—
Income Taxes Receivable	91,256			12,305
Other	187,276			206,679
Total	3,383,373			3,385,216
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	50,973,760			49,592,091
Other Property, Plant and Equipment	3,883,759			4,008,564
Total Property, Plant and Equipment	54,857,519			53,600,655
Less: Accumulated Depreciation, Depletion and Amortization	(29,277,359		)	(27,893,577		)
Total Property, Plant and Equipment, Net	25,580,160			25,707,078
Deferred Income Taxes	16,888			16,140
Other Assets	283,196			190,767
Total Assets	$	29,263,617		$	29,299,201
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,615,170		$	1,511,826
Accrued Taxes Payable	155,458			118,411
Dividends Payable	96,145			96,120
Liabilities from Price Risk Management Activities	—			61,817
Current Portion of Long-Term Debt	606,454			6,579
Other	249,027			232,538
Total	2,722,254			2,027,291

Long-Term Debt	6,380,350			6,979,779
Other Liabilities	1,199,778			1,282,142
Deferred Income Taxes	5,059,520			5,028,408
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized at June 30, 2017, 640,000,000 Shares Authorized at December 31, 2016, 577,711,399 Shares Issued at June 30, 2017 and 576,950,272 Shares Issued at December 31, 2016	205,777			205,770
Additional Paid in Capital	5,485,832			5,420,385
Accumulated Other Comprehensive Loss	(17,490		)	(19,010		)
Retained Earnings	8,256,359			8,398,118
Common Stock Held in Treasury, 316,339 Shares at June 30, 2017 and 250,155 Shares at December 31, 2016	(28,763		)	(23,682		)
Total Stockholders' Equity	13,901,715			13,981,581
Total Liabilities and Stockholders' Equity	$	29,263,617		$	29,299,201

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

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EOG RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)



	Six Months Ended June 30,
	2017			2016
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Income (Loss)	$	51,570		$	(764,334	)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	1,681,420			1,791,382
Impairments	272,121			144,331
Stock-Based Compensation Expenses	58,061			59,471
Deferred Income Taxes	35,162			(384,294		)
Losses on Asset Dispositions, Net	25,674			6,403
Other, Net	(6,691		)	29,991
Dry Hole Costs	27			74
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	(71,466		)	38,938
Net Cash Received from Settlements of Commodity Derivative Contracts	2,591			2,852
Excess Tax Benefits from Stock-Based Compensation	—			(11,811		)
Other, Net	(185		)	5,008
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	103,786			(22,572		)
Inventories	(6,129		)	95,813
Accounts Payable	76,704			(203,358		)
Accrued Taxes Payable	(39,124		)	93,320
Other Assets	(61,089		)	(33,589		)
Other Liabilities	(66,869		)	1,565
Changes in Components of Working Capital Associated with Investing and Financing Activities	(79,138		)	(54,453		)
Net Cash Provided by Operating Activities	1,976,425			794,737
Investing Cash Flows
Additions to Oil and Gas Properties	(1,885,417		)	(1,143,549		)
Additions to Other Property, Plant and Equipment	(88,076		)	(44,584		)
Proceeds from Sales of Assets	175,260			252,529
Changes in Components of Working Capital Associated with Investing Activities	79,138			54,477
Net Cash Used in Investing Activities	(1,719,095		)	(881,127		)
Financing Cash Flows
Net Commercial Paper Repayments	—			(259,718		)
Long-Term Debt Borrowings	—			991,097
Long-Term Debt Repayments	—			(400,000		)
Dividends Paid	(192,984		)	(184,036		)
Excess Tax Benefits from Stock-Based Compensation	—			11,811
Treasury Stock Purchased	(21,678		)	(28,755		)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	9,608			10,624
Debt Issuance Costs	—			(1,602		)
Repayment of Capital Lease Obligation	(3,251		)	(3,150		)
Other, Net	—			(24		)
Net Cash (Used in) Provided by Financing Activities	(208,305		)	136,247
Effect of Exchange Rate Changes on Cash	523			11,359
Increase in Cash and Cash Equivalents	49,548			61,216
Cash and Cash Equivalents at Beginning of Period	1,599,895			718,506
Cash and Cash Equivalents at End of Period	$	1,649,443		$	779,722

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

-5-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

General. The condensed 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 condensed 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, 2016, filed on February 27, 2017 (EOG's 2016 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, 2017, are not necessarily indicative of the results to be expected for the full year.

Effective January 1, 2017, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-09, "Improvements to Employee Share-Based Payment Accounting" (ASU 2016-09), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures and minimum statutory tax withholdings and prescribes certain disclosures to be made in the period the new standard is adopted. There was no impact to retained earnings with respect to excess tax benefits. EOG began recognizing all excess tax benefits and tax deficiencies as income tax provision or benefit as discrete events. Net excess tax benefits recognized within income tax provision was $12 million for the six months ended June 30, 2017. The treatment of forfeitures did not change as EOG elected to continue the current process of estimating the number of forfeitures. As such, this had no cumulative effect on retained earnings. EOG elected to present changes to the statements of cash flows on a prospective transition method.

Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated its December 31, 2016 balance sheet to reclassify $169 million of current deferred income tax assets as noncurrent.

Recently Issued Accounting Standards. In February 2017, the Financial Accounting Standards Board (FASB) issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) - Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets” (ASU 2017-05). ASU 2017-05 clarifies the scope and application of Accounting Standards Codification (ASC) 610-20 to the sale or transfer of nonfinancial assets and, in substance, nonfinancial assets to noncustomers, including partial sales. ASU 2017-05 is effective for interim and annual periods beginning after December 15, 2017, and early adoption is permitted, at the same time of adoption of ASU 2014-09, “Revenue From Contracts With Customers” (ASU 2014-09). EOG does not intend to early adopt ASU 2017-05. EOG is reviewing the provisions of ASU 2017-05 in connection with the adoption of ASU 2014-09 to determine its impact on its consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" (ASU 2017-01), which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition and early adoption is permitted. EOG is evaluating ASU 2017-01 to determine the impact on its consolidated financial statements and related disclosures.

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 reduces existing diversity in practice by providing guidance on the classification of eight specific cash receipts and cash payments transactions in the statement of cash flows. The new standard is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, and is required to be adopted using a retrospective approach, if practicable. Early adoption is permitted. EOG does not expect the adoption of the new standard to have a material impact on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity's lease transactions will also be required. ASU 2016-02 defines a lease as "a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration." ASU 2016-02 is effective for interim and annual periods beginning after December 31, 2018 and early adoption is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. EOG is reviewing the provisions of ASU 2016-02 to determine the impact on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU 2014-09, 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 is effective for interim and annual reporting periods beginning after December 15, 2017, and early adoption is permitted. The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the "entitlements" method of revenue recognition used by EOG. EOG will adopt ASU 2014-09 utilizing the modified retrospective approach with a cumulative adjustment to retained earnings on January 1, 2018. Based on its current assessments to-date, EOG does not anticipate the provisions of ASU 2014-09 will have a material impact on EOG's consolidated financial statements and related disclosures. EOG continues to analyze ASU 2014-09 in order to finalize implementation and determine the impact on EOG's financial statements and related disclosures.

2. Stock-Based Compensation

As more fully discussed in Note 7 to the Consolidated Financial Statements included in EOG's 2016 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) 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,
	2017		2016		2017		2016
Lease and Well	$	9.6	$	8.9	$	20.5	$	19.3
Gathering and Processing Costs	0.2		0.3		0.4		0.6
Exploration Costs	5.3		5.0		11.5		11.5
General and Administrative	12.5		12.9		25.7		28.1
Total	$	27.6	$	27.1	$	58.1	$	59.5

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 and restricted stock units, performance units and performance stock and other stock-based awards. At June 30, 2017, approximately 20.9 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. The fair value of stock option grants 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 $11.1 million and $13.0 million during the three months ended June 30, 2017 and 2016, respectively, and $22.1 million and $26.2 million during the six months ended June 30, 2017 and 2016, 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, 2017 and 2016 are as follows:



	Stock Options/SARs						ESPP
	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Weighted Average Fair Value of Grants	$	26.64		$	21.04		$	24.28		$	17.56
Expected Volatility	30.46		%	35.90		%	30.33		%	36.79		%
Risk-Free Interest Rate	1.39		%	0.93		%	0.65		%	0.49		%
Dividend Yield	0.68		%	0.91		%	0.69		%	0.82		%
Expected Life	5.3 years			5.3 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.

The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2017 and 2016 (stock options and SARs in thousands):



	Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
	Number of Stock Options/SARs		Weighted Average Grant Price		Number of Stock Options/SARs		Weighted Average Grant Price
Outstanding at January 1	9,850		$	75.53	10,744		$	67.98
Granted	16		96.41		11		71.51
Exercised ⁽¹⁾	(783	)	57.05		(790	)	44.31
Forfeited	(189	)	89.40		(150	)	85.91
Outstanding at June 30 ⁽²⁾	8,894		$	76.90	9,815		$	69.61
Vested or Expected to Vest ⁽³⁾	8,594		$	76.53	9,490		$	69.24
Exercisable at June 30 ⁽⁴⁾	4,973		$	68.43	5,638		$	61.50


(1)	The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2017 and 2016 was $33.5 million and $26.8 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, 2017 and 2016 was $147.8 million and $173.1 million, respectively. At June 30, 2017 and 2016, the weighted average remaining contractual life was 3.6 years and 3.6 years, respectively.


(3)	The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2017 and 2016 was $145.7 million and $170.3 million, respectively. At June 30, 2017 and 2016, the weighted average remaining contractual life was 3.5 years and 3.6 years, respectively.


(4)	The total intrinsic value of stock options/SARs exercisable at June 30, 2017 and 2016 was $120.9 million and $137.7 million, respectively. At June 30, 2017 and 2016, the weighted average remaining contractual life was 2.2 years and 2.4 years, respectively.

At June 30, 2017, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $75.6 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.3 years.

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 $15.6 million and $13.7 million for the three months ended June 30, 2017 and 2016, respectively, and $34.2 million and $32.4 million for the six months ended June 30, 2017 and 2016, respectively.

The following table sets forth restricted stock and restricted stock unit transactions for the six-month periods ended June 30, 2017 and 2016 (shares and units in thousands):



	Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
	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	3,962		$	79.63	4,908		$	70.35
Granted	437		98.97		306		75.56
Released ⁽¹⁾	(407	)	63.20		(798	)	61.36
Forfeited	(143	)	83.92		(203	)	76.97
Outstanding at June 30 ⁽²⁾	3,849		$	83.40	4,213		$	72.11


(1)	The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2017 and 2016 was $40.4 million and $60.8 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date the restricted stock and restricted stock units are released.


(2)	The total intrinsic value of restricted stock and restricted stock units outstanding at June 30, 2017 and 2016 was $348.4 million and $351.5 million, respectively.

At June 30, 2017, unrecognized compensation expense related to restricted stock and restricted stock units totaled $151.1 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.5 years.

Performance Units and Performance Stock. EOG has granted performance units and/or performance stock (Performance Awards) to its executive officers annually since 2012. As more fully discussed in the grant agreements, the performance metric applicable to the Performance Awards is EOG's total shareholder return over a three-year performance period relative to the total shareholder return of a designated group of peer companies (Performance Period). Upon the application of the performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Awards granted could be outstanding. Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of Performance Awards will generally "cliff" vest five years from the date of grant. The fair value of the Performance Awards is estimated using a Monte Carlo simulation.

At December 31, 2016, 545,290 Performance Awards were outstanding. Upon completion of the Performance Period for the Performance Awards granted in 2013, a performance multiple of 200% was applied to the 2013 grants resulting in an additional grant of 118,834 Performance Awards in February 2017. A total of 89,224 Performance Awards were released during the six months ended June 30, 2017, with a total intrinsic value of $9.0 million, based upon the closing price of EOG's common stock on the release date. Upon the application of the performance multiple at the completion of the remaining Performance Periods, a minimum of 299,540 and a maximum of 850,260 Performance Awards could be outstanding. There were 574,900 Performance Awards outstanding as of June 30, 2017. The total intrinsic value of Performance Awards outstanding at June 30, 2017 was $52.0 million.

Stock-based compensation expense related to the Performance Award grants totaled $0.9 million and $0.4 million for the three month periods ended June 30, 2017 and 2016, respectively, and $1.8 million and $0.9 million for the six months ended June 30, 2017 and 2016, respectively. At June 30, 2017, unrecognized compensation expense related to Performance Awards totaled $8.6 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.5 years.

-9-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the three-month and six-month periods ended June 30, 2017 and 2016 (in thousands, except per share data):



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
Numerator for Basic and Diluted Earnings Per Share -
Net Income (Loss)	$	23,053	$	(292,558	)	$	51,570	$	(764,334	)
Denominator for Basic Earnings Per Share -
Weighted Average Shares	574,439		547,335			574,162		547,029
Potential Dilutive Common Shares -
Stock Options/SARs	1,452		—			1,669		—
Restricted Stock/Units and Performance Units/Stock	2,592		—			2,742		—
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares	578,483		547,335			578,573		547,029
Net Income (Loss) Per Share
Basic	$	0.04	$	(0.53	)	$	0.09	$	(1.40	)
Diluted	$	0.04	$	(0.53	)	$	0.09	$	(1.40	)

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 3.4 million and 10.2 million shares for the three months ended June 30, 2017 and 2016, respectively, and 2.0 million and 10.4 million shares for the six months ended June 30, 2017 and 2016, respectively. For both the three months and six months ended June 30, 2016, 4.6 million shares of restricted stock, restricted stock units and performance units were excluded.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the six-month periods ended June 30, 2017 and 2016 (in thousands):



	Six Months Ended June 30,
	2017		2016
Interest ⁽¹⁾	$	136,733	$	118,120
Income Taxes, Net of Refunds Received	$	98,157	$	(10,997	)


(1)	Net of capitalized interest of $14 million and $17 million for the six months ended June 30, 2017 and 2016, respectively.

EOG's accrued capital expenditures at June 30, 2017 and 2016 were $488 million and $371 million, respectively.

Non-cash investing activities for the six months ended June 30, 2017, included non-cash additions of $154 million to EOG's oil and gas properties as a result of property exchanges.

-10-

EOG RESOURCES, INC.

NOTES TO CONDENSED 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, 2017 and 2016 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net Operating Revenues and Other
United States	$	2,530,885		$	1,704,320		$	5,050,734		$	2,983,989
Trinidad	72,299			62,731			146,222			125,524
Other International ⁽¹⁾	9,288			8,689			26,081			20,576
Total	$	2,612,472		$	1,775,740		$	5,223,037		$	3,130,089
Operating Income (Loss)
United States	$	130,314		$	(280,593	)	$	249,845		$	(905,577	)
Trinidad	32,360			17,054			48,773			25,932
Other International ⁽¹⁾	(34,766		)	(24,634		)	(62,964		)	(46,669		)
Total	127,908			(288,173		)	235,654			(926,314		)
Reconciling Items
Other Income (Expense), Net	4,972			(20,996		)	8,123			(25,433		)
Interest Expense, Net	(70,413		)	(71,108		)	(141,928		)	(139,498		)
Income (Loss) Before Income Taxes	$	62,467		$	(380,277	)	$	101,849		$	(1,091,245	)


(1)	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Total assets by reportable segment are presented below at June 30, 2017 and December 31, 2016 (in thousands):



	At June 30, 2017		At December 31, 2016
Total Assets
United States	$	27,676,982	$	27,746,851
Trinidad	947,166		889,253
Other International ⁽¹⁾	639,469		663,097
Total	$	29,263,617	$	29,299,201


(1)	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

-11-

EOG RESOURCES, INC.

NOTES TO CONDENSED 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, 2017 and 2016 (in thousands):



	Six Months Ended June 30,
	2017			2016
Carrying Amount at Beginning of Period	$	912,926		$	811,554
Liabilities Incurred	19,276			18,258
Liabilities Settled ⁽¹⁾	(28,726		)	(18,043		)
Accretion	17,010			16,521
Revisions	3,646			(635		)
Foreign Currency Translations	3,808			(6,745		)
Carrying Amount at End of Period	$	927,940		$	820,910

Current Portion	$	33,922		$	8,349
Noncurrent Portion	$	894,018		$	812,561


(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 Condensed Consolidated Balance Sheets.

7. Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the six-month period ended June 30, 2017, are presented below (in thousands):



	Six Months Ended June 30, 2017
Balance at January 1	$	—
Additions Pending the Determination of Proved Reserves	2,995
Reclassifications to Proved Properties	—
Costs Charged to Expense	—
Balance at June 30	$	2,995

-12-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8. Commitments and Contingencies

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

9. Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, Trinidad and the United Kingdom, and a defined benefit pension plan covering certain of its employees in Trinidad. For the six months ended June 30, 2017 and 2016, EOG's total costs recognized for these pension plans were $18.4 million and $17.2 million, respectively. EOG also has postretirement medical and dental plans in place for eligible employees and their dependents in the United States and Trinidad, the costs of which are not material.

10. Long-Term Debt

EOG had no outstanding commercial paper borrowings or uncommitted credit facility borrowings at June 30, 2017, and did not utilize any such borrowings during the six months ended June 30, 2017. During the six months ended June 30, 2016, EOG utilized commercial paper, bearing market interest rates, for various corporate financing purposes. The average borrowings outstanding under the commercial paper program were $210 million during the six months ended June 30, 2016. The weighted average interest rate for commercial paper borrowings was 0.76% during the six months ended June 30, 2016.

At June 30, 2017, $600 million aggregate principal amount of EOG's 5.875% Senior Notes due 2017 was reclassified as Current Portion of Long-Term Debt on the Condensed Consolidated Balance Sheets based upon its intent and ability to repay these notes upon maturity with cash in the third quarter of 2017.

EOG currently has a $2.0 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement has a scheduled maturity date of July 21, 2020, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. Advances under the Agreement will accrue interest based, at EOG's option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar rate) or the base rate (as defined in the Agreement) plus an applicable margin. At June 30, 2017, there were no borrowings or letters of credit outstanding under the Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 2.22% and 4.25%, respectively.

-13-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11. Fair Value Measurements

As more fully discussed in Note 13 to the Consolidated Financial Statements included in EOG's 2016 Annual Report, certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Condensed 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, 2017 and December 31, 2016 (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, 2017
Financial Assets:
Natural Gas Swaps	$	—	$	1	$	—	$	1
Natural Gas Options/Collars	—		7		—		7

At December 31, 2016
Financial Assets:
Natural Gas Options/Collars	$	—	$	1	$	—	$	1
Financial Liabilities:
Crude Oil Swaps	$	—	$	36	$	—	$	36
Natural Gas Swaps	—		4		—		4
Natural Gas Options/Collars	—		22		—		22

The estimated fair value of commodity derivative contracts was based upon forward commodity price curves based on quoted market prices. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 6.

Proved oil and gas properties and other assets with a carrying amount of $253 million were written down to their fair value of $92 million, resulting in pretax impairment charges of $161 million for the six months ended June 30, 2017. Included in the $161 million pretax impairment charges are $138 million of impairments of proved oil and gas properties and other property, plant and equipment for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded pretax impairment charges of $23 million for a commodity price-related write-down of other assets.

EOG utilized average prices per acre from comparable market transactions as the basis for determining the fair value of unproved properties received in non-cash property exchanges. See Note 4.

Fair Value of Debt. At June 30, 2017 and December 31, 2016, EOG had outstanding $6,990 million aggregate principal amount of senior notes, which had estimated fair values at such dates of approximately $7,181 million and $7,190 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 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12. Risk Management Activities

Commodity Price Risk. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2016 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.

Commodity Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. Presented below is a comprehensive summary of EOG's crude oil basis swap contracts for the six months ended June 30, 2017. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.



Crude Oil Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)


2018
January 1, 2018 through December 31, 2018	15,000	$	1.063

2019
January 1, 2019 through December 31, 2019	20,000	$	1.075

On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the below table. Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the six months ended June 30, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2017
January 1, 2017 through February 28, 2017 (closed)	35,000	$	50.04
March 1, 2017 through June 30, 2017 (closed)	30,000	50.05

On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table.

-15-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the six months ended June 30, 2017, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).



Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2017
March 1, 2017 through July 31, 2017 (closed)	30,000	$	3.10
August 1, 2017 through November 30, 2017	30,000	3.10

2018
March 1, 2018 through November 30, 2018	35,000	$	3.00

EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price.

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the six months ended June 30, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.



Natural Gas Option Contracts
	Call Options Sold			Put Options Purchased
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)		Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2017
March 1, 2017 through July 31, 2017 (closed)	213,750	$	3.44	171,000	$	2.92
August 1, 2017 through November 30, 2017	213,750	3.44		171,000	2.92

2018
March 1, 2018 through November 30, 2018	120,000	$	3.38	96,000	$	2.94

-16-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts for the six months ended June 30, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.



Natural Gas Collar Contracts
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)	Ceiling Price		Floor Price
2017
March 1, 2017 through July 31, 2017 (closed)	80,000	$	3.69	$	3.20
August 1, 2017 through November 30, 2017	80,000	3.69		3.20

The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at June 30, 2017 and December 31, 2016. Certain amounts may be presented on a net basis on the Condensed 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, 2017		December 31, 2016
Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	5	$	—
Noncurrent portion	Other Assets	3		1
Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	—	$	62

-17-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

Credit Risk. Notional contract amounts are used to express the magnitude of a financial derivative. 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 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 December 31, 2016. EOG had no collateral posted and held no collateral at June 30, 2017 and December 31, 2016.

13. Acquisitions and Divestitures

Yates Entities. On October 4, 2016, EOG completed its previously announced mergers and related asset purchase transactions with Yates Petroleum Corporation (YPC), Abo Petroleum Corporation (ABO), MYCO Industries, Inc. (MYCO) and certain affiliated entities (collectively with YPC, ABO and MYCO, the Yates Entities). For a further discussion of these transactions, refer to Note 17 to the Consolidated Financial Statements in EOG's 2016 Annual Report. The assets of the Yates Entities include producing wells in addition to acreage in the Delaware Basin Core, the Powder River Basin, the Permian Basin Northwest Shelf and other Western basins.

EOG accounted for the mergers with YPC, ABO and MYCO and the related asset purchase transactions as a business combination under the acquisition method with EOG as the acquirer. Under the acquisition method, the consideration transferred is allocated to the assets acquired and liabilities assumed based on their estimated fair values, with any excess of the consideration transferred over the estimated fair value of the identifiable net assets acquired recorded as goodwill. EOG did not record goodwill in connection with these transactions.

There were no changes during the six months ended June 30, 2017, to the preliminary purchase price allocation. Certain data necessary to complete the purchase price allocation is preliminary, and includes, but is not limited to, the final valuations of oil and gas properties, the valuation of off-market transportation contracts and the calculation of deferred taxes based upon the underlying tax basis of assets acquired and liabilities assumed. EOG believes the estimates used are reasonable but are subject to change as additional information becomes available.

Other. During the six months ended June 30, 2017, EOG recognized a net loss on asset dispositions of $26 million and received proceeds of approximately $175 million primarily from the sale of producing assets, unproved leasehold and other property, plant and equipment in Oklahoma and Texas. During the six months ended June 30, 2016, EOG recognized a net loss on asset dispositions of $6 million and received proceeds of approximately $253 million primarily from sales of producing properties and acreage in the Permian Basin and Oklahoma.

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

United States. 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.

Crude oil and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs) and natural gas and the availability of other worldwide energy supplies, EOG is unable to predict what changes may occur in crude oil and condensate, NGL, and natural gas prices in the future. The market prices of crude oil and condensate, NGLs and natural gas in 2017 will continue to impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position and results of operations. For the first half of 2017, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $50.07 per barrel and $3.19 per million British thermal units (MMBtu), respectively, representing increases of 26% and 60%, respectively, from the average NYMEX prices for the same period in 2016. Based on its 2017 drilling and completion plans, EOG expects 2017 total production and total crude oil production to increase as compared to 2016.

During the first half of 2017, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG maintained the strategy of looking for opportunities to add drilling inventory through leasehold acquisitions, farm-ins or tactical acquisitions and to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 77% of EOG's United States production during the first half of 2017 as compared to 72% for the same comparable period of 2016. During the first half of 2017, drilling and completion activities occurred primarily in the Eagle Ford play, Delaware Basin play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas and Wyoming.

Trinidad. 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), Modified U(b) Block and the Sercan Area (formerly known as the EMZ area) have been developed and are producing natural gas, which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC) and crude oil and condensate which is sold to the Petroleum Company of Trinidad and Tobago Limited. In early 2017, EOG completed and brought on-line two net wells finishing its program in the Sercan area. During the second quarter of 2017, EOG drilled a net well, which was completed in July 2017, and participated in a seismic survey program with a joint venture partner. Also, in June 2017, EOG and NGC signed a new multi-year contract under which EOG will supply future natural gas volumes to NGC beginning in 2019. For the remainder of 2017, EOG expects to drill and complete three additional net wells.

-19-

Other International. In the United Kingdom, EOG produces crude oil from its 100% working interest East Irish Sea Conwy project. During the second quarter of 2017, the Conwy production was off-line due to operational issues. Additional downtime is expected in the second half of 2017 due to planned facility improvements and ongoing operational issues.

In the Sichuan Basin, Sichuan Province, China, EOG drilled four natural gas wells in the first half of 2017 as part of the continuing development of the Bajiaochang Field, which natural gas is sold under a long-term contract to PetroChina. In the second half of 2017, EOG expects to complete the four aforementioned wells and drill a fifth well.

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

Capital Structure. One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 33% at both June 30, 2017 and December 31, 2016. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On February 15, 2017, the Board of Directors approved an amendment to EOG's Restated Certificate of Incorporation to increase the number of EOG's authorized shares of common stock from 640 million to 1,280 million. EOG's stockholders approved the increase at the Annual Meeting of Stockholders on April 27, 2017, and the amendment was filed with the Delaware Secretary of State on April 28, 2017.

Total anticipated 2017 capital expenditures are estimated to range from approximately $3.7 billion to $4.1 billion, excluding acquisitions. The majority of 2017 expenditures will be focused on United States crude oil drilling activities. 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, joint development agreements and similar arrangements 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 months and six months ended June 30, 2017 and 2016 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10‑Q.

Three Months Ended June 30, 2017 vs. Three Months Ended June 30, 2016

Net Operating Revenues. During the second quarter of 2017, net operating revenues increased $836 million, or 47%, to $2,612 million from $1,776 million for the same period of 2016. 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 2017 increased $489 million, or 37%, to $1,816 million from $1,327 million for the same period of 2016. EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $9 million for the second quarter of 2017 compared to net losses of $44 million for the same period of 2016. Gathering, processing and marketing revenues for the second quarter of 2017 increased $294 million, or 61%, to $779 million from $485 million for the same period of 2016. Net losses on asset dispositions for the second quarter of 2017 were $9 million compared to $16 million for the same period of 2016.

-21-

Wellhead volume and price statistics for the three-month periods ended June 30, 2017 and 2016 were as follows:



	Three Months Ended June 30,
	2017		2016
Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	333.1		265.4
Trinidad	0.8		0.8
Other International ⁽²⁾	0.8		1.5
Total	334.7		267.7
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	47.51	$	43.87
Trinidad	39.64		35.91
Other International ⁽²⁾	35.13		—
Composite	47.46		43.65
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	86.6		84.3
Other International ⁽²⁾	—		—
Total	86.6		84.3
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	18.65	$	14.56
Other International ⁽²⁾	—		—
Composite	18.65		14.56
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	755		820
Trinidad	320		349
Other International ⁽²⁾	21		25
Total	1,096		1,194
Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	2.14	$	1.18
Trinidad	2.40		1.89
Other International ⁽²⁾	3.66		3.35
Composite	2.25		1.44
Crude Oil Equivalent Volumes (MBoed) ⁽⁴⁾
United States	545.6		486.3
Trinidad	54.1		59.0
Other International ⁽²⁾	4.2		5.8
Total	603.9		551.1

Total MMBoe ⁽⁴⁾	55.0		50.1


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


(2)	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.


(3)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements).

(4)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs 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 2017 increased $386 million, or 36%, to $1,445 million from $1,059 million for the same period of 2016. The increase was primarily due to an increase of 67 MBbld, or 25%, in wellhead crude oil and condensate production ($270 million) and a higher composite wellhead crude oil and condensate price ($116 million). Increased production was primarily due to increases in the Permian Basin, Rocky Mountain area, the Eagle Ford and from the 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and other affiliated entities (collectively, the Yates Entities). EOG's composite wellhead crude oil and condensate price for the second quarter of 2017 increased 9% to $47.46 per barrel compared to $43.65 per barrel for the same period of 2016.

NGL revenues for the second quarter of 2017 increased $35 million, or 32%, to $147 million from $112 million for the same period of 2016 due primarily to a higher composite average price. EOG's composite NGL price for the second quarter of 2017 increased 28% to $18.65 per barrel compared to $14.56 per barrel for the same period of 2016.

Wellhead natural gas revenues for the second quarter of 2017 increased $68 million, or 44%, to $224 million from $156 million for the same period of 2016. The increase was due to a higher composite wellhead natural gas price ($81 million), partially offset by a decrease in natural gas deliveries ($13 million). Natural gas deliveries for the second quarter of 2017 decreased 98 MMcfd, or 8%, compared to the same period of 2016 due primarily to lower deliveries in the United States (65 MMcfd) and Trinidad (29 MMcfd). The decrease in the United States was due primarily to the 2016 sale of EOG's Johnson County, Texas, Barnett Shale, Haynesville and South Texas natural gas assets, partially offset by increased production of associated natural gas from the Permian Basin and the Rocky Mountain area and the 2016 transactions with the Yates Entities. The decrease in Trinidad was primarily due to lower contractual deliveries. EOG's composite wellhead natural gas price for the second quarter of 2017 increased 56% to $2.25 per Mcf compared to $1.44 per Mcf for the same period of 2016.

During the second quarter of 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $9 million compared to net losses of $44 million for the same period of 2016. During the second quarter of 2017, net cash received for settlements of financial commodity derivative contracts was $0.7 million compared to net cash paid of $15 million for the same period of 2016.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. 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. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations 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 as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the second quarter of 2017 decreased $17 million as compared to the same period of 2016. The decrease primarily reflects lower margins in 2017 on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities and sand sales.

-23-

Operating and Other Expenses. For the second quarter of 2017, operating expenses of $2,485 million were $421 million higher than the $2,064 million incurred during the second quarter of 2016. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2017 and 2016:



	Three Months Ended June 30,
	2017		2016
Lease and Well	$	4.64	$	4.36
Transportation Costs	3.39		3.59
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	15.22		16.66
Other Property, Plant and Equipment	0.52		0.57
General and Administrative (G&A)	1.97		1.95
Interest Expense, Net	1.28		1.42
Total ⁽¹⁾	$	27.02	$	28.55


(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, DD&A and G&A for the three months ended June 30, 2017, compared to the same period of 2016 are set forth below. See "Net Operating Revenues" above for a discussion of wellhead 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 $255 million for the second quarter of 2017 increased $37 million from $218 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($28 million) and the United Kingdom ($9 million).

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease to a downstream point of sale. Transportation costs include transportation fees, 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 $186 million for the second quarter of 2017 increased $7 million from $179 million for the same prior year period primarily due to higher transportation costs in the Permian Basin ($9 million), the Rocky Mountain area ($9 million) and the Eagle Ford ($5 million) and the addition of the Yates Entities in 2016 ($5 million), partially offset by the 2016 sale of EOG's Johnson County, Texas, Barnett Shale and Haynesville natural gas assets ($20 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 and 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.

-24-

DD&A expenses for the second quarter of 2017 increased $3 million to $865 million from $862 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2017 were $3 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($95 million), partially offset by decreased rates in the United States ($86 million) and Trinidad ($3 million) and decreased production in Trinidad ($3 million). DD&A unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower cost as a result of increased efficiencies.

G&A expenses of $109 million for the second quarter of 2017 increased $11 million from $98 million for the same prior year period primarily due to increases in professional, legal and other services ($19 million) and by an increase in employee-related expenses ($12 million) primarily due to the 2016 transactions with the Yates Entities, partially offset by a decrease in employee-related expenses in connection with certain voluntary retirements in 2016 ($20 million).

Exploration costs of $35 million for the second quarter of 2017 increased $4 million from $31 million for the same prior year period primarily due to increased geological and geophysical costs in the United States.

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 individually significant acquisition costs are analyzed on a property-by-property basis for any impairment in value. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset. If the 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 $79 million for the second quarter of 2017 were $6 million higher than impairments for the same prior year period primarily due to increased impairments of other assets in the United States ($23 million), partially offset by decreased amortization of unproved property costs in the United States ($17 million). EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $24 million and $1 million for the second quarter of 2017 and 2016, respectively.

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 $35 million for the second quarter of 2017 compared to $29 million for the same prior year period primarily due to increased operating costs in the United Kingdom ($8 million), partially offset by lower operating costs in the Fort Worth Basin Barnett Shale ($3 million).

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 2017 increased $37 million to $130 million (7.2% of wellhead revenues) compared to $93 million (7.0% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increases in severance/production taxes, primarily as a result of increased wellhead revenues in the United States.

Other income (expense), net for the second quarter of 2017 increased $26 million compared to the same prior year period primarily due to a decrease in foreign currency exchange losses ($22 million) and decreased deferred compensation expense ($4 million).

EOG recognized an income tax provision of $39 million for the second quarter of 2017 compared to an income tax benefit of $88 million in the second quarter of 2016, primarily due to pretax income in 2017 as compared to a pretax loss in 2016. The net effective tax rate for the second quarter of 2017 increased to 63% from 23% for the second quarter of 2016. The higher effective tax rate was primarily due to additional deferred state income taxes resulting from changes in state apportionment factors and foreign losses in the United Kingdom and Canada for which tax benefits are not recorded due to valuation allowances.

-25-

Six Months Ended June 30, 2017 vs. Six Months Ended June 30, 2016

Net Operating Revenues. During the first six months of 2017, net operating revenues increased $2,093 million, or 67%, to $5,223 million from $3,130 million for the same period of 2016. Total wellhead revenues for the first six months of 2017 increased $1,309 million, or 56%, to $3,631 million from $2,322 million for the same period of 2016. During the first six months of 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $71 million compared to net losses of $39 million for the same period of 2016. Gathering, processing and marketing revenues for the first six months of 2017 increased $686 million, or 84%, to $1,505 million from $819 million for the same period of 2016. Net losses on asset dispositions for the first six months of 2017 were $26 million compared to $6 million for the same period of 2016.

Wellhead volume and price statistics for the six-month periods ended June 30, 2017 and 2016 were as follows:



	Six Months Ended June 30,
	2017		2016
Crude Oil and Condensate Volumes (MBbld)
United States	322.8		265.6
Trinidad	0.8		0.8
Other International	1.6		1.4
Total	325.2		267.8
Average Crude Oil and Condensate Prices ($/Bbl) ⁽¹⁾
United States	$	48.89	$	37.36
Trinidad	40.63		29.83
Other International	44.66		—
Composite	48.85		37.23
Natural Gas Liquids Volumes (MBbld)
United States	82.7		81.8
Other International	—		—
Total	82.7		81.8
Average Natural Gas Liquids Prices ($/Bbl)
United States	$	20.06	$	12.54
Other International	—		—
Composite	20.06		12.54
Natural Gas Volumes (MMcfd)
United States	742		825
Trinidad	314		355
Other International	21		25
Total	1,077		1,205
Average Natural Gas Prices ($/Mcf) ⁽¹⁾
United States	$	2.23	$	1.22
Trinidad	2.48		1.88
Other International	3.71		3.49
Composite	2.33		1.47
Crude Oil Equivalent Volumes (MBoed)
United States	529.2		484.9
Trinidad	53.1		59.9
Other International	5.1		5.6
Total	587.4		550.4

Total MMBoe	106.3		100.2


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

-26-

Wellhead crude oil and condensate revenues for the first six months of 2017 increased $1,063 million, or 59%, to $2,876 million from $1,813 million for the same period of 2016 due primarily to a higher composite wellhead crude oil and condensate price ($684 million) and an increase of 57 MBbld, or 21%, in wellhead crude oil and condensate production ($379 million). Increased production was primarily due to increases in the Permian Basin and the Rocky Mountain area. EOG's composite wellhead crude oil and condensate price for the first six months of 2017 increased 31% to $48.85 per barrel compared to $37.23 per barrel for the same period of 2016.

NGL revenues for the first six months of 2017 increased $113 million, or 61%, to $300 million from $187 million for the same period of 2016 due primarily to a higher composite average price. EOG's composite NGL price for the first six months of 2017 increased 60% to $20.06 per barrel compared to $12.54 per barrel for the same period of 2016.

Wellhead natural gas revenues for the first six months of 2017 increased $133 million, or 41%, to $455 million from $322 million for the same period of 2016 primarily due to a higher composite wellhead natural gas price ($169 million), partially offset by a decrease of 128 MMcfd, or 11%, in natural gas deliveries ($36 million) primarily due to lower production in the United States (83 MMcfd) and Trinidad (41 MMcfd). The decrease in the United States was due primarily to the 2016 sale of EOG's Johnson County, Texas, Barnett Shale, Haynesville and South Texas natural gas assets, partially offset by increased production of associated natural gas from the Permian Basin and the Rocky Mountain area and the 2016 transactions with the Yates Entities. EOG's composite wellhead natural gas price for the first six months of 2017 increased 58% to $2.33 per Mcf compared to $1.47 per Mcf for the same period of 2016.

During the first six months of 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $71 million compared to net losses of $39 million for the same period of 2016. During the first six months of 2017 and 2016, net cash received for settlements of financial commodity derivative contracts was $3 million. The net cash received for financial commodity derivative contracts during the first six months of 2017 included certain early-terminated crude oil price swaps.

Gathering, processing and marketing revenues less marketing costs for the first six months of 2017 decreased $20 million as compared to the same period of 2016. The decrease primarily reflects lower margins in 2017 on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.

Operating and Other Expenses. For the first six months of 2017, operating expenses of $4,987 million were $931 million higher than the $4,056 million incurred during the same period of 2016. The following table presents the costs per Boe for the six-month periods ended June 30, 2017 and 2016:



	Six Months Ended June 30,
	2017		2016
Lease and Well	$	4.81	$	4.59
Transportation Costs	3.43		3.69
DD&A -
Oil and Gas Properties	15.28		17.32
Other Property, Plant and Equipment	0.54		0.56
G&A	1.94		1.98
Interest Expense, Net	1.33		1.39
Total ⁽¹⁾	$	27.33	$	29.53


(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, 2017, compared to the same period of 2016 are set forth below. See "Net Operating Revenues" above for a discussion of wellhead volumes.

Lease and well expenses of $511 million for the first six months of 2017 increased $52 million from $459 million for the same prior year period primarily due to higher operating and maintenance costs in the United States ($34 million) and the United Kingdom ($13 million) and workover expenditures in the United States ($15 million).

-27-

Transportation costs of $365 million for the first six months of 2017 decreased $5 million from $370 million for the same prior year period primarily due to the 2016 sale of EOG's Johnson County, Texas, Barnett Shale and Haynesville natural gas assets ($42 million), partially offset by higher transportation costs in the Permian Basin ($19 million), the Rocky Mountain area ($10 million) and the addition of the Yates Entities in 2016 ($8 million).

DD&A expenses for the first six months of 2017 decreased $110 million to $1,681 million from $1,791 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2017 were $111 million lower than the same prior year period. The decrease primarily reflects decreased rates in the United States ($229 million) and Trinidad ($12 million) and decreased production in Trinidad ($9 million), partially offset by increased production in the United States ($137 million) and the United Kingdom ($4 million). DD&A unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower cost as a result of increased efficiencies.

Exploration costs of $92 million for the first six months of 2017 increased $32 million from $60 million for the same prior year period primarily due to increased geological and geophysical costs in Trinidad ($20 million) and the United States ($11 million).

G&A expenses of $206 million for the first six months of 2017 increased $8 million from $198 million for the same prior year period primarily due to increases in professional, legal and other services ($23 million) and by an increase in employee-related expenses ($25 million) primarily due to the 2016 transactions with the Yates Entities, partially offset by a decrease in employee-related expenses in connection with certain voluntary retirements in 2016 ($42 million).

Gathering and processing costs for the first six months of 2017 increased $15 million to $73 million compared to the same prior year period primarily due to increased operating costs in the United Kingdom ($19 million), partially offset by decreased operating costs in the Fort Worth Basin Barnett Shale area ($4 million).

Impairments of $272 million for the first six months of 2017 were $128 million higher than impairments for the same prior year period primarily due to increased impairments of proved properties and other assets in the United States ($159 million), partially offset by decreased amortization of unproved property costs in the United States ($31 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. For the first six months of 2017, proved property and other asset impairments in the United States were primarily related to the sale of legacy natural gas assets. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $161 million and $2 million for the first six months of 2017 and 2016, respectively.

Taxes other than income for the first six months of 2017 increased $106 million to $260 million (7.2% of wellhead revenues) from $154 million (6.6% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes ($91 million) as a result of increased wellhead revenues and increased ad valorem/property taxes ($14 million) in the United States and a decrease in credits available to EOG in 2017 for Texas high-cost gas severance tax rate reductions ($2 million).

Other income (expense), net for the first six months of 2017 increased $33 million compared to the same prior year period primarily due to a decrease in foreign currency exchange losses.

EOG recognized an income tax provision of $50 million for the first six months of 2017 compared to an income tax benefit of $327 million for the same period in 2016, primarily due to pretax income in 2017 as compared to a pretax loss. The net effective tax rate for the first six months of 2017 increased to 49% from 30% for the first six months of 2016. The higher effective tax rate was primarily due to foreign losses in the United Kingdom and Canada for which tax benefits are not recorded due to valuation allowances and additional deferred state income taxes resulting from changes in state apportionment factors.

-28-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2017, were funds generated from operations and proceeds from sales of assets. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; other property, plant and equipment expenditures; and purchases of treasury stock in connection with stock compensation plans. During the first six months of 2017, EOG's cash balance increased $49 million to $1,649 million from $1,600 million at December 31, 2016.

Net cash provided by operating activities of $1,976 million for the first six months of 2017 increased $1,181 million compared to the same period of 2016 primarily due to an increase in wellhead revenues ($1,309 million) and favorable changes in working capital and other assets and liabilities ($200 million), partially offset by an increase in cash operating expenses ($211 million) and an unfavorable change in net cash paid for income taxes ($109 million).

Net cash used in investing activities of $1,719 million for the first six months of 2017 increased by $838 million compared to the same period of 2016 due to an increase in additions to oil and gas properties ($742 million), a decrease in proceeds from the sales of assets ($77 million) and an increase in additions to other property, plant and equipment ($43 million), partially offset by favorable changes in working capital associated with investing activities ($25 million).

Net cash used in financing activities of $208 million for the first six months of 2017 included cash dividend payments ($193 million) and purchases of treasury stock in connection with stock compensation plans ($22 million). Net cash provided by financing activities of $136 million for the first six months of 2016 included net proceeds from the issuance of long-term debt ($991 million). Cash used in financing activities for the first six months of 2016 included repayments of long-term debt ($400 million), net commercial paper repayments ($260 million), cash dividend payments ($184 million) and purchases of treasury stock in connection with stock compensation plans ($29 million).

Total Expenditures. For the year 2017, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $3.7 billion to $4.1 billion, excluding acquisitions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2017 and 2016 (in millions):



	Six Months Ended June 30,
	2017		2016
Expenditure Category
Capital
Exploration and Development Drilling	$	1,447	$	903
Facilities	309		182
Leasehold Acquisitions ⁽¹⁾	265		31
Property Acquisitions	4		10
Capitalized Interest	14		17
Subtotal	2,039		1,143
Exploration Costs	92		60
Dry Hole Costs	—		—
Exploration and Development Expenditures	2,131		1,203
Asset Retirement Costs	24		19
Total Exploration and Development Expenditures	2,155		1,222
Other Property, Plant and Equipment	90		45
Total Expenditures	$	2,245	$	1,267


(1)	Leasehold acquisitions included $154 million in 2017 related to non-cash property exchanges.

-29-

Total exploration and development expenditures of $2,131 million for the first six months of 2017 were $928 million higher than the same period of 2016 primarily due to increased exploration and drilling expenditures in the United States ($481 million) and Trinidad ($52 million); increased facilities expenditures ($127 million); increased leasehold acquisitions ($234 million, including $154 million of non-cash property exchanges); and increased geological and geophysical expenditures ($31 million). Exploration and development expenditures for the first six months of 2017 of $2,131 million consisted of $1,749 million in development drilling and facilities, $364 million in exploration (including $154 million of non-cash property exchanges), $14 million in capitalized interest and $4 million in property acquisitions. Exploration and development expenditures for the first six months of 2016 of $1,203 million consisted of $1,078 million in development drilling and facilities, $98 million in exploration, $10 million in property acquisitions, and $17 million in capitalized interest.

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

Commodity Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2016, filed on February 27, 2017, 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 Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact is reflected in Cash Flows from Operating Activities on the Condensed Consolidated Statements of Cash Flows.

The total fair value of EOG's commodity derivative contracts was reflected on the Condensed Consolidated Balance Sheets at June 30, 2017, as a net asset of $8 million.

Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. Presented below is a comprehensive summary of EOG's crude oil basis swap contracts through August 1, 2017. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.



Crude Oil Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)


2018
January 1, 2018 through December 31, 2018	15,000	$	1.063

2019
January 1, 2019 through December 31, 2019	20,000	$	1.075

-30-

On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the below table. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through August 1, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2017
January 1, 2017 through February 28, 2017 (closed)	35,000	$	50.04
March 1, 2017 through June 30, 2017 (closed)	30,000	50.05

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through August 1, 2017, with notional volumes expressed in MMBtu per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).



Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2017
March 1, 2017 through August 31, 2017 (closed)	30,000	$	3.10
September 1, 2017 through November 30, 2017	30,000	3.10

2018
March 1, 2018 through November 30, 2018	35,000	$	3.00

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In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.



Natural Gas Option Contracts
	Call Options Sold			Put Options Purchased
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)		Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2017
March 1, 2017 through August 31, 2017 (closed)	213,750	$	3.44	171,000	$	2.92
September 1, 2017 through November 30, 2017	213,750	3.44		171,000	2.92

2018
March 1, 2018 through November 30, 2018	120,000	$	3.38	96,000	$	2.94

EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.



Natural Gas Collar Contracts
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)	Ceiling Price		Floor Price
2017
March 1, 2017 through August 31, 2017 (closed)	80,000	$	3.69	$	3.20
September 1, 2017 through November 30, 2017	80,000	3.69		3.20

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Information Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, 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, reduce or otherwise control operating and capital costs, 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, extent and duration of changes in prices for, supplies of, 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 maximize 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 and condensate, natural gas liquids, 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 the acquisition of licenses, leases and properties, 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 to which EOG is successful in its completion of planned asset dispositions;


•	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;

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•	political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;


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


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


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


•	physical, electronic and cyber security breaches; and


•	the other factors described under ITEM 1A, Risk Factors, on pages 13 through 22 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, 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 duration and 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 40 through 44 of EOG's Annual Report on Form 10-K for the year ended December 31, 2016, filed on February 27, 2017 (EOG's 2016 Annual Report); and (ii) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-27 through F-30 of EOG's 2016 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 Condensed 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 Condensed Consolidated Financial Statements, which is incorporated herein by reference.

On July 31, 2017, EOG executed a consent decree with the North Dakota Department of Health (NDDOH) regarding alleged violations of North Dakota's air pollution control laws and related provisions of the federal Clean Air Act. After execution by the NDDOH, the consent decree will be filed with the North Dakota District Court for the South Central Judicial District (Court). EOG expects the Court will issue its order approving the consent decree and resolving the alleged violations raised therein.

The consent decree provides that EOG will be subject to a base penalty of $400,000. The consent decree further provides that the base penalty may be reduced by up to 60 percent in respect of voluntary leak detection and repair (LDAR) efforts by EOG and EOG's development and submission of a quality assurance/quality control (QA/QC) plan to assist with minimizing air emissions. Additionally, pursuant to the terms of the consent decree, EOG may fund a supplemental environmental project (SEP) to offset up to 50 percent of the final penalty amount.

EOG anticipates being able to qualify for a substantial portion of the available penalty reductions. EOG also intends to fund a SEP to the full extent contemplated by the consent decree. After taking into account such reductions and the SEP-related offset, EOG expects that the penalty it will pay to the NDDOH will be approximately $100,000.

EOG does not believe that the penalty amount paid to the NDDOH, the expenditures resulting from its LDAR efforts and development and submission of a QA/QC plan or the amount funded for the SEP will have a material adverse effect on EOG's financial position, results of operations or cash flows. EOG's consent decree generally follows the same format as the consent decrees that the NDDOH has negotiated with other North Dakota operators.

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, 2017 - April 30, 2017	8,791	$	95.99	—	6,386,200
May 1, 2017 - May 31, 2017	12,899	93.14		—	6,386,200
June 1, 2017 -June 30, 2017	10,985	89.79		—	6,386,200
Total	32,675	92.78		—

(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, restricted stock unit, or performance 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 repurchase 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 2017, 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 Quarterly Report on Form 10-Q.

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ITEM 6. EXHIBITS



Exhibit No.		Description

3.1	-	Certificate of Amendment of Restated Certificate of Incorporation, dated April 28, 2017 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed May 2, 2017).

* 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 Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - Three and Six Months Ended June 30, 2017 and 2016, (ii) the Condensed Consolidated Balance Sheets - June 30, 2017 and December 31, 2016, (iii) the Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2017 and 2016 and (iv) the Notes to Condensed 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 1, 2017	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

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EXHIBIT INDEX



Exhibit No.		Description

3.1	-	Certificate of Amendment of Restated Certificate of Incorporation, dated April 28, 2017 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed May 2, 2017).

* 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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