EOG RESOURCES INC - Quarter Report: 2018 June (Form 10-Q)

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, 2018

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		579,200,784 (as of July 25, 2018)

EOG RESOURCES, INC.

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Condensed Consolidated Statements of Income and Comprehensive Income - Three Months Ended June 30, 2018 and 2017 and Six Months Ended June 30, 2018 and 2017	3

		Condensed Consolidated Balance Sheets - June 30, 2018 and December 31, 2017	4

		Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2018 and 2017	5

		Notes to Condensed Consolidated Financial Statements	6

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	38

	ITEM 4.	Controls and Procedures	38

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	39

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

	ITEM 4.	Mine Safety Disclosures	39

	ITEM 6.	Exhibits	40

SIGNATURES			41

-2-

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EOG RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Thousands, Except Per Share Data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Operating Revenues and Other
Crude Oil and Condensate	$	2,377,528		$	1,445,454		$	4,478,836		$	2,875,515
Natural Gas Liquids	286,354			146,907			507,769			300,351
Natural Gas	300,845			224,008			600,611			454,610
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	(185,883		)	9,446			(245,654		)	71,466
Gathering, Processing and Marketing	1,436,436			778,797			2,538,258			1,505,334
Losses on Asset Dispositions, Net	(6,317		)	(8,916		)	(21,286		)	(25,674		)
Other, Net	29,114			16,776			60,705			41,435
Total	4,238,077			2,612,472			7,919,239			5,223,037
Operating Expenses
Lease and Well	314,604			255,186			614,668			510,963
Transportation Costs	177,797			186,356			354,754			365,070
Gathering and Processing Costs	109,169			34,746			210,514			72,890
Exploration Costs	47,478			34,711			82,314			91,605
Dry Hole Costs	4,902			27			4,902			27
Impairments	51,708			78,934			116,317			272,121
Marketing Costs	1,420,463			790,599			2,526,853			1,527,135
Depreciation, Depletion and Amortization	848,674			865,384			1,597,265			1,681,420
General and Administrative	104,083			108,507			198,781			205,745
Taxes Other Than Income	194,268			130,114			373,352			260,407
Total	3,273,146			2,484,564			6,079,720			4,987,383
Operating Income	964,931			127,908			1,839,519			235,654
Other Income (Expense), Net	(8,551		)	4,972			(7,824		)	8,123
Income Before Interest Expense and Income Taxes	956,380			132,880			1,831,695			243,777
Interest Expense, Net	63,444			70,413			125,400			141,928
Income Before Income Taxes	892,936			62,467			1,706,295			101,849
Income Tax Provision	196,205			39,414			370,975			50,279
Net Income	$	696,731		$	23,053		$	1,335,320		$	51,570
Net Income Per Share
Basic	$	1.21		$	0.04		$	2.32		$	0.09
Diluted	$	1.20		$	0.04		$	2.30		$	0.09
Dividends Declared per Common Share	$	0.1850		$	0.1675		$	0.3700		$	0.3350
Average Number of Common Shares
Basic	576,135			574,439			575,953			574,162
Diluted	580,375			578,483			580,007			578,573
Comprehensive Income
Net Income	$	696,731		$	23,053		$	1,335,320		$	51,570
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(3,229		)	1,260			1,773			1,569
Other, Net of Tax	6			(86		)	12			(49		)
Other Comprehensive Income (Loss)	(3,223		)	1,174			1,785			1,520
Comprehensive Income	$	693,508		$	24,227		$	1,337,105		$	53,090

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

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EOG RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

(Unaudited)



	June 30, 2018			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,008,215		$	834,228
Accounts Receivable, Net	1,907,990			1,597,494
Inventories	670,994			483,865
Assets from Price Risk Management Activities	1,840			7,699
Income Taxes Receivable	364,119			113,357
Other	278,694			242,465
Total	4,231,852			3,279,108
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	55,319,050			52,555,741
Other Property, Plant and Equipment	4,141,479			3,960,759
Total Property, Plant and Equipment	59,460,529			56,516,500
Less: Accumulated Depreciation, Depletion and Amortization	(32,306,734		)	(30,851,463		)
Total Property, Plant and Equipment, Net	27,153,795			25,665,037
Deferred Income Taxes	17,067			17,506
Other Assets	689,666			871,427
Total Assets	$	32,092,380		$	29,833,078
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,336,952		$	1,847,131
Accrued Taxes Payable	213,461			148,874
Dividends Payable	106,569			96,410
Liabilities from Price Risk Management Activities	195,457			50,429
Current Portion of Long-Term Debt	1,262,540			356,235
Other	182,322			226,463
Total	4,297,301			2,725,542

Long-Term Debt	5,172,257			6,030,836
Other Liabilities	1,304,624			1,275,213
Deferred Income Taxes	3,865,804			3,518,214
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 579,597,990 Shares Issued at June 30, 2018 and 578,827,768 Shares Issued at December 31, 2017	205,796			205,788
Additional Paid in Capital	5,591,643			5,536,547
Accumulated Other Comprehensive Loss	(17,512		)	(19,297		)
Retained Earnings	11,714,656			10,593,533
Common Stock Held in Treasury, 410,969 Shares at June 30, 2018 and 350,961 Shares at December 31, 2017	(42,189		)	(33,298		)
Total Stockholders' Equity	17,452,394			16,283,273
Total Liabilities and Stockholders' Equity	$	32,092,380		$	29,833,078

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,
	2018			2017
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	1,335,320		$	51,570
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	1,597,265			1,681,420
Impairments	116,317			272,121
Stock-Based Compensation Expenses	67,289			58,061
Deferred Income Taxes	347,586			35,162
Losses on Asset Dispositions, Net	21,286			25,674
Other, Net	13,507			(6,691		)
Dry Hole Costs	4,902			27
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	245,654			(71,466		)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(88,334		)	2,591
Other, Net	(261		)	(185		)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(309,751		)	103,786
Inventories	(192,219		)	(6,129		)
Accounts Payable	455,977			76,704
Accrued Taxes Payable	22,535			(39,124		)
Other Assets	(62,843		)	(61,089		)
Other Liabilities	(53,168		)	(66,869		)
Changes in Components of Working Capital Associated with Investing and Financing Activities	(27,279		)	(79,138		)
Net Cash Provided by Operating Activities	3,493,783			1,976,425
Investing Cash Flows
Additions to Oil and Gas Properties	(2,980,286		)	(1,885,417		)
Additions to Other Property, Plant and Equipment	(144,858		)	(88,076		)
Proceeds from Sales of Assets	8,276			175,260
Changes in Components of Working Capital Associated with Investing Activities	27,250			79,138
Net Cash Used in Investing Activities	(3,089,618		)	(1,719,095		)
Financing Cash Flows
Dividends Paid	(203,610		)	(192,984		)
Treasury Stock Purchased	(32,023		)	(21,678		)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	11,145			9,608
Repayment of Capital Lease Obligation	(3,354		)	(3,251		)
Changes in Components of Working Capital Associated with Financing Activities	29			—
Net Cash Used in Financing Activities	(227,813		)	(208,305		)
Effect of Exchange Rate Changes on Cash	(2,365		)	523
Increase in Cash and Cash Equivalents	173,987			49,548
Cash and Cash Equivalents at Beginning of Period	834,228			1,599,895
Cash and Cash Equivalents at End of Period	$	1,008,215		$	1,649,443

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

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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, 2017, filed on February 27, 2018 (EOG's 2017 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, 2018, are not necessarily indicative of the results to be expected for the full year.

Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs 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. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09.

EOG presents disaggregated revenues by type of commodity within its Condensed Consolidated Statements of Income and Comprehensive Income and by geographic areas defined as operating segments. See Note 5.

In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of a deduction to Revenues within its Condensed Consolidated Statements of Income and Comprehensive Income. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the three and six months ended June 30, 2018, were as follows (in thousands):

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)



	Three Months Ended June 30, 2018						Six Months Ended June 30, 2018
	As Reported		Amounts Without Adoption of ASU 2014-09		Effect of Change		As Reported		Amounts Without Adoption of ASU 2014-09		Effect of Change
Operating Revenues and Other
Crude Oil and Condensate	$	2,377,528	$	2,377,528	$	—	$	4,478,836	$	4,478,836	$	—
Natural Gas Liquids	286,354		284,898		1,456		507,769		504,543		3,226
Natural Gas	300,845		257,652		43,193		600,611		514,273		86,338
Gathering, Processing and Marketing	1,436,436		1,431,077		5,359		2,538,258		2,527,313		10,945
Total Operating Revenues and Other	4,238,077		4,188,069		50,008		7,919,239		7,818,730		100,509
Operating Expenses
Gathering and Processing Costs	109,169		64,520		44,649		210,514		120,950		89,564
Marketing Costs	1,420,463		1,415,104		5,359		2,526,853		2,515,908		10,945
Total Operating Expenses	3,273,146		3,223,138		50,008		6,079,720		5,979,211		100,509
Operating Income	964,931		964,931		—		1,839,519		1,839,519		—

Revenues are recognized for the sale of crude oil and condensate, natural gas liquids (NGLs) and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers on January 1, 2018 and June 30, 2018, were $1,343 million and $1,608 million, respectively, and are included in Accounts Receivable, Net on the Condensed Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Operating Expenses.

Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of NGLs to a customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers.

Under typical arrangements, sales of NGLs are recognized when control transfers after processing occurs either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with processing fees recognized as Gathering and Processing Costs.

Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices.

Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with processing and gathering third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues.

Recently Issued Accounting Standards. In March 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-05, "Income Taxes (Topic 740) - Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118" (ASU 2018-05). In December 2017, the United States (U.S.) enacted the Tax Cuts and Jobs Act (TCJA), which made significant changes to U.S. federal income tax law. Shortly after enactment of the TCJA, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which provides guidance on accounting for the impact of the TCJA. ASU 2018-05 codified various paragraphs of SAB 118 and was effective upon issuance. Under SAB 118, an entity would use a similar approach as the measurement period provided in the Business Combinations Topic of the Accounting Standards Codification (ASC). An entity will recognize those matters for which the accounting can be completed. For matters that have not been completed, the entity would either (1) recognize provisional amounts to the extent that they are reasonably able to be estimated and adjust them over time as more information becomes available or (2) for any specific income tax effects of the TCJA for which a reasonable estimate cannot be determined, continue to apply the Income Taxes Topic of the ASC on the basis of the provisions of the tax laws that were in effect immediately before the TCJA was signed into law. EOG has prepared its condensed consolidated financial statements for the three and six months ended June 30, 2018 in accordance with ASU 2018-05. EOG expects to have all provisional amounts finalized by the fourth quarter of 2018.

As discussed in EOG's 2017 Annual Report, provisional amounts were recorded for the impact of the statutory rate reduction from 35% to 21% and the deemed repatriation tax on foreign earnings. EOG has not made any measurement period adjustments related to these items during the three and six months ended June 30, 2018, because the foreign earnings and profits study has not been completed and the impact of certain tax elections on EOG's 2017 federal tax filings have not been fully analyzed.

Additionally, EOG recorded a provisional amount in 2017 for its refundable alternative minimum tax (AMT) credits due to the lack of guidance, at that time, on whether any portion of these credits would be sequestered due to a federal budgetary provision. In the first quarter of 2018, the Internal Revenue Service (IRS) affirmed that any refundable AMT credits resulting from the TCJA would be subject to sequestration. EOG does not expect further clarification from the IRS or Office of Management and Budget and therefore considers the accounting for sequestration on its refundable AMT credits complete.

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 certain 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." In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842" (ASU 2018-01), which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. Additionally, in July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842) - Targeted Improvements” (ASU 2018-11), which permits an entity (i) to apply the provisions of ASU 2016-02 at the adoption date instead of the earliest period presented in the financial statements, and, as a lessor, (ii) to account for lease and nonlease components as a single component as the nonlease components would otherwise be accounted for under the provisions of ASU 2014-09. ASU 2016-02 and other related ASUs are effective for interim and annual periods beginning after December 31, 2018, and early application is permitted. Based on the provisions of ASU 2018-11 and other related ASUs, lessees and lessors may recognize and measure leases at the beginning of the earliest period presented in the financial statements, defined as the effective date, using a modified retrospective approach, or at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings.

EOG is continuing its assessment of ASU 2016-02 by implementing its project plan, evaluating certain operational and corporate policies and processes, further defining its population of leases and reviewing numerous contracts. EOG plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases. Additionally, EOG plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. EOG does not intend to early-adopt ASU 2016-02 and other related ASUs and has not determined which transition method it will use.

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Stock-Based Compensation

As more fully discussed in Note 7 to the Consolidated Financial Statements included in EOG's 2017 Annual Report, EOG maintains various stock-based compensation plans. Stock-based compensation expense is included on the Condensed Consolidated Statements of Income and Comprehensive Income based upon the job function of the employees receiving the grants as follows (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Lease and Well	$	11.4	$	9.6	$	24.2	$	20.5
Gathering and Processing Costs	0.1		0.2		0.2		0.4
Exploration Costs	5.7		5.3		12.6		11.5
General and Administrative	14.6		12.5		30.3		25.7
Total	$	31.8	$	27.6	$	67.3	$	58.1

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, 2018, approximately 16.9 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.

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 $11.7 million and $11.1 million during the three months ended June 30, 2018 and 2017, respectively, and $23.7 million and $22.1 million during the six months ended June 30, 2018 and 2017, 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, 2018 and 2017 are as follows:



	Stock Options/SARs						ESPP
	Six Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Weighted Average Fair Value of Grants	$	29.18		$	26.64		$	23.27		$	24.28
Expected Volatility	28.88		%	30.46		%	22.04		%	30.33		%
Risk-Free Interest Rate	2.23		%	1.39		%	1.60		%	0.65		%
Dividend Yield	0.67		%	0.68		%	0.66		%	0.69		%
Expected Life	5.0 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.

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EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth stock option and SAR transactions for the six-month periods ended June 30, 2018 and 2017 (stock options and SARs in thousands):



	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
	Number of Stock Options/SARs		Weighted Average Grant Price		Number of Stock Options/SARs		Weighted Average Grant Price
Outstanding at January 1	9,103		$	83.89	9,850		$	75.53
Granted	32		110.17		16		96.41
Exercised ⁽¹⁾	(1,662	)	71.33		(783	)	57.05
Forfeited	(124	)	92.07		(189	)	89.40
Outstanding at June 30 ⁽²⁾	7,349		$	86.71	8,894		$	76.90
Vested or Expected to Vest ⁽³⁾	7,006		$	86.44	8,594		$	76.53
Exercisable at June 30 ⁽⁴⁾	2,938		$	78.74	4,973		$	68.43


(1)	The total intrinsic value of stock options/SARs exercised for the six months ended June 30, 2018 and 2017 was $74.5 million and $33.5 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, 2018 and 2017 was $277.2 million and $147.8 million, respectively. At June 30, 2018 and 2017, the weighted average remaining contractual life was 4.3 years and 3.6 years, respectively.


(3)	The total intrinsic value of stock options/SARs vested or expected to vest at June 30, 2018 and 2017 was $266.2 million and $145.7 million, respectively. At June 30, 2018 and 2017, the weighted average remaining contractual life was 4.3 years and 3.5 years, respectively.


(4)	The total intrinsic value of stock options/SARs exercisable at June 30, 2018 and 2017 was $134.2 million and $120.9 million, respectively. At June 30, 2018 and 2017, the weighted average remaining contractual life was 2.7 years and 2.2 years, respectively.

At June 30, 2018, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled $76.9 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Stock-based compensation expense related to restricted stock and restricted stock units totaled $19.0 million and $15.6 million for the three months ended June 30, 2018 and 2017, respectively, and $41.3 million and $34.2 million for the six months ended June 30, 2018 and 2017, respectively.

The following table sets forth restricted stock and restricted stock unit transactions for the six-month periods ended June 30, 2018 and 2017 (shares and units in thousands):



	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
	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	3,905		$	88.57	3,962		$	79.63
Granted	309		103.52		437		98.97
Released ⁽¹⁾	(331	)	69.55		(407	)	63.20
Forfeited	(120	)	91.28		(143	)	83.92
Outstanding at June 30 ⁽²⁾	3,763		$	91.39	3,849		$	83.40


(1)	The total intrinsic value of restricted stock and restricted stock units released for the six months ended June 30, 2018 and 2017 was $34.9 million and $40.4 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, 2018 and 2017 was $468.2 million and $348.4 million, respectively.

-10-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At June 30, 2018, unrecognized compensation expense related to restricted stock and restricted stock units totaled $153.2 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 years.

Performance Units and Performance Stock. EOG has granted performance units and/or performance stock (collectively, 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. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Award grants totaled $1.1 million and $0.9 million for the three-month periods ended June 30, 2018 and 2017, respectively, and $2.3 million and $1.8 million for the six-month periods ended June 30, 2018 and 2017, respectively.

The following table sets forth the Performance Awards transactions for the six-month periods ended June 30, 2018 and 2017:



	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
	Number of Units		Weighted Average Price per Grant Date		Number of Units		Weighted Average Price per Grant Date
Outstanding at January 1	502,331		$	90.96	545,290		$	80.92
Granted	—		—		—		—
Granted for Performance Multiple ⁽¹⁾	71,805		101.87		118,834		84.43
Released ⁽²⁾	—		—		(89,224	)	84.43
Forfeited	—		—		—		—
Outstanding at June 30 ⁽³⁾	574,136	(4)	$	92.33	574,900		$	81.10


(1)	Upon completion of the Performance Period for the Performance Awards granted in 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2018 and February 2017, respectively.


(2)	The total intrinsic value of Performance Awards released during the six months ended June 30, 2017 was approximately $9.0 million. The intrinsic value is based upon the closing price of EOG's common stock on the date the Performance Awards are released.


(3)	The total intrinsic value of Performance Awards outstanding at June 30, 2018 and 2017 was approximately $71.4 million and $52.0 million, respectively.


(4)	Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 292,054 and a maximum of 856,218 Performance Awards could be outstanding.

At June 30, 2018, unrecognized compensation expense related to Performance Awards totaled $6.0 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.5 years.

-11-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and six-month periods ended June 30, 2018 and 2017 (in thousands, except per share data):



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Numerator for Basic and Diluted Earnings Per Share -
Net Income	$	696,731	$	23,053	$	1,335,320	$	51,570
Denominator for Basic Earnings Per Share -
Weighted Average Shares	576,135		574,439		575,953		574,162
Potential Dilutive Common Shares -
Stock Options/SARs	1,365		1,452		1,237		1,669
Restricted Stock/Units and Performance Units/Stock	2,875		2,592		2,817		2,742
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares	580,375		578,483		580,007		578,573
Net Income Per Share
Basic	$	1.21	$	0.04	$	2.32	$	0.09
Diluted	$	1.20	$	0.04	$	2.30	$	0.09

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 were zero and 3.4 million shares for the three months ended June 30, 2018 and 2017, respectively, and were zero and 2.0 million shares, respectively, for the six months ended June 30, 2018 and 2017, respectively.

4. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the six-month periods ended June 30, 2018 and 2017 (in thousands):



	Six Months Ended June 30,
	2018		2017
Interest ⁽¹⁾	$	133,148	$	136,733
Income Taxes, Net of Refunds Received	$	62,777	$	98,157


(1)	Net of capitalized interest of $11 million and $14 million for the six months ended June 30, 2018 and 2017, respectively.

EOG's accrued capital expenditures at June 30, 2018 and 2017 were $724 million and $488 million, respectively.

Non-cash investing activities for the six months ended June 30, 2018, included additions of $83 million to EOG's oil and gas properties as a result of property exchanges and an addition of $48 million to EOG's other property, plant and equipment in connection with a capital lease transaction in the Permian Basin. Non-cash investing activities for the six months ended June 30, 2017, included additions of $154 million to EOG's oil and gas properties as a result of property exchanges.

-12-

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, 2018 and 2017 (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Operating Revenues and Other
United States	$	4,114,610		$	2,530,885		$	7,685,744		$	5,050,734
Trinidad	81,611			72,299			162,624			146,222
Other International ⁽¹⁾	41,856			9,288			70,871			26,081
Total	$	4,238,077		$	2,612,472		$	7,919,239		$	5,223,037
Operating Income (Loss)
United States	$	946,883		$	130,314		$	1,792,736		$	249,845
Trinidad	27,821			32,360			68,118			48,773
Other International ⁽¹⁾	(9,773		)	(34,766		)	(21,335		)	(62,964		)
Total	964,931			127,908			1,839,519			235,654
Reconciling Items
Other Income (Expense), Net	(8,551		)	4,972			(7,824		)	8,123
Interest Expense, Net	(63,444		)	(70,413		)	(125,400		)	(141,928		)
Income Before Income Taxes	$	892,936		$	62,467		$	1,706,295		$	101,849


(1)	Other International primarily consists of EOG's United Kingdom, China and Canada operations.

Total assets by reportable segment are presented below at June 30, 2018 and December 31, 2017 (in thousands):



	At June 30, 2018		At December 31, 2017
Total Assets
United States	$	31,114,907	$	28,312,599
Trinidad	624,358		974,477
Other International ⁽¹⁾	353,115		546,002
Total	$	32,092,380	$	29,833,078


(1)	Other International primarily consists of EOG's United Kingdom, China and Canada operations.

-13-

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, 2018 and 2017 (in thousands):



	Six Months Ended June 30,
	2018			2017
Carrying Amount at January 1	$	946,848		$	912,926
Liabilities Incurred	25,496			19,276
Liabilities Settled ⁽¹⁾	(8,184		)	(28,726		)
Accretion	17,941			17,010
Revisions	(148		)	3,646
Foreign Currency Translations	(547		)	3,808
Carrying Amount at June 30	$	981,406		$	927,940

Current Portion	$	18,892		$	33,922
Noncurrent Portion	$	962,514		$	894,018


(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, 2018, are presented below (in thousands):



	Six Months Ended June 30, 2018
Balance at January 1	$	2,167
Additions Pending the Determination of Proved Reserves	3,512
Reclassifications to Proved Properties	(5,250		)
Costs Charged to Expense	(429		)
Balance at June 30	$	—

At June 30, 2018, all capitalized exploratory well costs had been capitalized for periods of less than one year.

8. Commitments and Contingencies

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

-14-

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9. Pension and Postretirement Benefits

EOG has defined contribution pension plans in place for most of its employees in the United States, 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, 2018 and 2017, EOG's total costs recognized for these pension plans were $20.2 million and $18.4 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 and Common Stock

Long-Term Debt. During the six months ended June 30, 2018, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. EOG did not utilize any such borrowings during the six months ended June 30, 2017. At June 30, 2018 and December 31, 2017, EOG had no outstanding commercial paper borrowings or uncommitted credit facility borrowings. The average borrowings outstanding under the commercial paper program were $17 million and zero during the six months ended June 30, 2018 and 2017, respectively. The weighted average interest rate for commercial paper borrowings during the six months ended June 30, 2018, was 1.97%.

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, 2018 and December 31, 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 at June 30, 2018, would have been 3.09% and 5.00%, respectively.

Common Stock. On August 2, 2018, EOG's Board of Directors increased the quarterly cash dividend on the common stock from the previous $0.1850 per share to $0.22 per share, effective beginning with the dividend to be paid on October 31, 2018, to stockholders of record as of October 17, 2018.

-15-

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 2017 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, 2018 and December 31, 2017 (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, 2018
Financial Assets:
Natural Gas Swaps	$	—	$	—	$	—	$	—
Natural Gas Options	—		2		—		2
Crude Oil Basis Swaps	—		83		—		83
Financial Liabilities:
Crude Oil Swaps	$	—	$	261	$	—	$	261

At December 31, 2017
Financial Assets:
Natural Gas Swaps	$	—	$	2	$	—	$	2
Natural Gas Options/Collars	—		6		—		6
Financial Liabilities:
Crude Oil Swaps	$	—	$	38	$	—	$	38
Crude Oil Basis Swaps	—		19		—		19

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 $163 million were written down to their fair value of $131 million, resulting in pretax impairment charges of $32 million for the six months ended June 30, 2018. Included in the $32 million pretax impairment charges are $21 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, 2018 and December 31, 2017, EOG had outstanding $6,390 million aggregate principal amount of senior notes, which had estimated fair values at such dates of approximately $6,419 million and $6,602 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.

-16-

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 2017 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 has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the six months ended June 30, 2018. 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.



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


2018
January 1, 2018 through July 31, 2018 (closed)	15,000	$	1.063
August 1, 2018 through December 31, 2018	15,000	1.063

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

-17-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the six months ended June 30, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.



Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)


2018
January 1, 2018 through July 31, 2018 (closed)	37,000	$	3.818
August 1, 2018 through December 31, 2018	37,000	3.818

2019
January 1, 2019 through December 31, 2019	8,000	$	5.660

Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the six months ended June 30, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2018
January 1, 2018 through June 30, 2018 (closed)	134,000	$	60.04
July 1, 2018 through December 31, 2018	134,000	60.04

Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the six months ended June 30, 2018, 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)
2018
March 1, 2018 through July 31, 2018 (closed)	35,000	$	3.00
August 1, 2018 through November 30, 2018	35,000	3.00

-18-

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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, 2018, 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)
2018
March 1, 2018 through July 31, 2018 (closed)	120,000	$	3.38	96,000	$	2.94
August 1, 2018 through November 30, 2018	120,000	3.38		96,000	2.94

The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at June 30, 2018 and December 31, 2017. 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, 2018		December 31, 2017
Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	2	$	8
Noncurrent portion	Other Assets	17		—
Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities ⁽¹⁾	$	195	$	50
Noncurrent portion	Other Liabilities	—		7


(1)	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $261 million, partially offset by gross assets of $66 million at June 30, 2018, and gross liabilities of $55 million, partially offset by gross assets of $5 million at December 31, 2017.

-19-

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 June 30, 2018 and December 31, 2017. EOG had no collateral posted and held no collateral at June 30, 2018 and December 31, 2017.

13. Acquisitions and Divestitures

During the six months ended June 30, 2018, EOG recognized a net loss on asset dispositions of $(21) million, primarily due to non-cash exchanges of unproved leasehold in New Mexico and Wyoming as well as the disposition of inventory and other assets, and received proceeds of approximately $8 million. 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.

-20-

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, natural gas liquids (NGLs) 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, NGLs and natural gas and the availability of other energy supplies, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, and natural gas prices in the future. The market prices of crude oil and condensate, NGLs and natural gas in 2018 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 six months of 2018, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $65.41 per barrel and $2.86 per million British thermal units (MMBtu), respectively, representing an increase of 31% and a decrease of 11%, respectively, from the average NYMEX prices for the same period in 2017. Market prices for NGLs are influenced by crude oil prices and the composition of NGL production including ethane, propane and butane, among others. Based on its 2018 drilling and completion plans, EOG expects 2018 total production and total crude oil production to increase as compared to 2017.

During the first half of 2018, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges 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 76% of EOG's United States production during the first half of 2018 and 77% for the same period of 2017. During the first half of 2018, EOG's 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 and crude oil and condensate 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, the Banyan Field and the Sercan 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. During the second quarter of 2018, EOG completed seismic surveys in the SECC Block and will continue to process that data through the remainder of 2018.

Other International. In the United Kingdom, EOG produces crude oil from its 100% working interest East Irish Sea Conwy Development project (Conwy Project). Beginning in the second quarter of 2017, the Conwy Project was off-line due to facility improvements and operational issues. During the first quarter of 2018, production from the Conwy Project resumed.

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In the Sichuan Basin, Sichuan Province, China, EOG constructed a new gas gathering line and completed the last previously-drilled well of a 2017 five-well development program in the Bajiaochang Field. The natural gas from the Bajiaochang Field is sold under a long-term contract to PetroChina. Additionally, EOG plans to drill five new wells in the Bajiaochang Field in the second half of 2018, of which four are expected to be completed by the end of 2018.

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 27% at June 30, 2018 and 28% at December 31, 2017. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

Total anticipated 2018 capital expenditures are estimated to range from approximately $5.4 billion to $5.8 billion, excluding acquisitions and non-cash transactions. The majority of 2018 expenditures will be focused on United States crude oil 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.

-22-

Results of Operations

The following review of operations for the three months and six months ended June 30, 2018 and 2017 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, 2018 vs. Three Months Ended June 30, 2017

Operating Revenues. During the second quarter of 2018, operating revenues increased $1,626 million, or 62%, to $4,238 million from $2,612 million for the same period of 2017. 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 2018 increased $1,149 million, or 63%, to $2,965 million from $1,816 million for the same period of 2017. EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $186 million for the second quarter of 2018 compared to net gains of $9 million for the same period of 2017. Gathering, processing and marketing revenues for the second quarter of 2018 increased $657 million, or 84%, to $1,436 million from $779 million for the same period of 2017. Net losses on asset dispositions were $6 million for the second quarter of 2018 compared to $9 million for the same period of 2017.

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Wellhead volume and price statistics for the three-month periods ended June 30, 2018 and 2017 were as follows:



	Three Months Ended June 30,
	2018			2017
Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	379.2			333.1
Trinidad	0.8			0.8
Other International ⁽²⁾	4.6			0.8
Total	384.6			334.7
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	67.91		$	47.51
Trinidad	60.57			39.64
Other International ⁽²⁾	70.88			35.13
Composite	67.93			47.46
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	112.9			86.6
Other International ⁽²⁾	—			—
Total	112.9			86.6
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	27.86		$	18.65
Other International ⁽²⁾	—			—
Composite	27.86			18.65
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	914			755
Trinidad	282			320
Other International ⁽²⁾	32			21
Total	1,228			1,096
Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	2.56		$	2.14
Trinidad	2.98			2.40
Other International ⁽²⁾	4.10			3.66
Composite	2.69		⁽⁴⁾	2.25
Crude Oil Equivalent Volumes (MBoed) ⁽⁵⁾
United States	644.4			545.6
Trinidad	47.8			54.1
Other International ⁽²⁾	10.0			4.2
Total	702.2			603.9

Total MMBoe ⁽⁵⁾	63.9			55.0


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


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


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

(4)

Includes a positive revenue adjustment of $0.39 per Mcf related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Condensed Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas revenues.

(5)

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.

-24-

Wellhead crude oil and condensate revenues for the second quarter of 2018 increased $933 million, or 65%, to $2,378 million from $1,445 million for the same period of 2017. The increase was primarily due to a higher composite wellhead crude oil and condensate price ($717 million) and an increase of 50 MBbld, or 15%, in wellhead crude oil and condensate production ($216 million). Increased production was primarily due to increases in the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and condensate price for the second quarter of 2018 increased 43% to $67.93 per barrel compared to $47.46 per barrel for the same period of 2017.

NGL revenues for the second quarter of 2018 increased $139 million, or 95%, to $286 million from $147 million for the same period of 2017 due primarily to a higher composite average price ($94 million) and an increase of 26 MBbld, or 30%, in production ($45 million). Increased production was primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the second quarter of 2018 increased 49% to $27.86 per barrel compared to $18.65 per barrel for the same period of 2017.

Wellhead natural gas revenues for the second quarter of 2018 increased $77 million, or 34%, to $301 million from $224 million for the same period of 2017. The increase was due to a higher composite wellhead natural gas price ($50 million) and an increase in natural gas deliveries ($27 million). Natural gas deliveries for the second quarter of 2018 increased 132 MMcfd, or 12%, compared to the same period of 2017 due primarily to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and the Eagle Ford, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the second quarter of 2018 increased 20% to $2.69 per Mcf compared to $2.25 per Mcf for the same period of 2017. This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.39 per Mcf related to the adoption of ASU 2014-09.

During the second quarter of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $186 million compared to net gains of $9 million for the same period of 2017. During the second quarter of 2018, net cash paid for settlements of financial commodity derivative contracts was $66 million compared to net cash received of $0.7 million for the same period of 2017.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with processing and gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be 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 to purchase third-party crude oil, natural gas and sand 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 2018 increased $28 million as compared to the same period of 2017 primarily due to higher margins on crude oil marketing activities.

Operating and Other Expenses. For the second quarter of 2018, operating expenses of $3,273 million were $788 million higher than the $2,485 million incurred during the second quarter of 2017. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2018 and 2017:



	Three Months Ended June 30,
	2018		2017
Lease and Well	$	4.92	$	4.64
Transportation Costs	2.78		3.39
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	12.83		15.22
Other Property, Plant and Equipment	0.45		0.52
General and Administrative (G&A)	1.63		1.97
Interest Expense, Net	0.99		1.28
Total ⁽¹⁾	$	23.60	$	27.02


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

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The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for the three months ended June 30, 2018, compared to the same period of 2017, are set forth below. See "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 $315 million for the second quarter of 2018 increased $60 million from $255 million for the same prior year period primarily due to increased operating and maintenance costs ($42 million), lease and well administrative expenses ($13 million) and workover expenditures ($11 million), all in the United States, partially offset by decreased operating and maintenance costs in the United Kingdom ($7 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

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), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs.

Transportation costs of $178 million for the second quarter of 2018 decreased $9 million from $186 million for the same prior year period primarily due to decreased transportation costs in the Barnett Shale ($16 million), Rocky Mountain area ($11 million) and the Eagle Ford ($6 million), partially offset by increased transportation costs in the Permian Basin ($27 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.

DD&A expenses for the second quarter of 2018 decreased $16 million to $849 million from $865 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2018 were $17 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($167 million), partially offset by increased production in the United States ($144 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 from drilling and completions operations.

G&A expense of $104 million for the second quarter of 2018 decreased $5 million from $109 million for the same prior year period primarily due to decreased professional, legal and other services ($13 million), partially offset by increased employee-related expenses ($6 million).

Interest expense, net of $63 million for the second quarter of 2018 decreased $7 million compared to the same prior year period primarily due to repayment in September 2017 of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017.

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets and, beginning January 1, 2018, natural gas processing fees from third parties. EOG pays third parties to process a portion of its natural gas production to extract NGLs. See Note 1 to the Condensed Consolidated Financial Statements for discussion related to EOG's adoption of ASU 2014-09.

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Gathering and processing costs increased $74 million to $109 million for the second quarter of 2018 compared to $35 million for the same prior year period primarily due to the adoption of ASU 2014-09 ($45 million) and increased operating costs in the Permian Basin ($12 million), the Eagle Ford ($10 million) and the United Kingdom ($5 million).

Exploration costs of $47 million for the second quarter of 2018 increased $12 million from $35 million for the same prior year period primarily due to increased geological and geophysical costs in Trinidad.

Impairments include amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. 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 offers from third-party purchasers as the basis for determining fair value.

Impairments of $52 million for the second quarter of 2018 were $27 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties and other assets in the United States ($14 million) and decreased amortization of unproved property costs in the United States ($13 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $10 million and $24 million for the second quarter of 2018 and 2017, respectively.

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

Taxes other than income for the second quarter of 2018 increased $64 million to $194 million (6.6% of wellhead revenues) compared to $130 million (7.2% 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 as a result of increased wellhead revenues in the United States.

Other income (expense), net for the second quarter of 2018 decreased $14 million compared to the same prior year period primarily due to an increase in foreign currency exchange losses ($8 million) and increased deferred compensation expense ($6 million).

EOG recognized an income tax provision of $196 million for the second quarter of 2018 compared to an income tax provision of $39 million in the second quarter of 2017, primarily due to an increase in pretax income. The net effective tax rate for 2018 decreased to 22% from 63% in 2017. The lower effective tax rate is mostly due to the reduction in the U.S. federal statutory tax rate to 21% in 2018 from 35% in 2017, foreign income in the United Kingdom for which no taxes are recorded due to valuation allowances and the absence of certain 2017 state income tax apportionment changes.

-27-

Six Months Ended June 30, 2018 vs. Six Months Ended June 30, 2017

Operating Revenues. During the first six months of 2018, operating revenues increased $2,696 million, or 52%, to $7,919 million from $5,223 million for the same period of 2017. Total wellhead revenues for the first six months of 2018 increased $1,956 million, or 54%, to $5,587 million from $3,631 million for the same period of 2017. During the first six months of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $246 million compared to net gains of $71 million for the same period of 2017. Gathering, processing and marketing revenues for the first six months of 2018 increased $1,033 million, or 69%, to $2,538 million from $1,505 million for the same period of 2017. Net losses on asset dispositions were $21 million for the first six months of 2018 compared to $26 million for the same period of 2017.

-28-

Wellhead volume and price statistics for the six-month periods ended June 30, 2018 and 2017 were as follows:



	Six Months Ended June 30,
	2018			2017
Crude Oil and Condensate Volumes (MBbld)
United States	369.5			322.8
Trinidad	0.9			0.8
Other International	3.6			1.6
Total	374.0			325.2
Average Crude Oil and Condensate Prices ($/Bbl) ⁽¹⁾
United States	$	66.13		$	48.89
Trinidad	57.59			40.63
Other International	71.14			44.66
Composite	66.16			48.85
Natural Gas Liquids Volumes (MBbld)
United States	106.8			82.7
Other International	—			—
Total	106.8			82.7
Average Natural Gas Liquids Prices ($/Bbl)
United States	$	26.27		$	20.06
Other International	—			—
Composite	26.27			20.06
Natural Gas Volumes (MMcfd)
United States	884			742
Trinidad	288			314
Other International	30			21
Total	1,202			1,077
Average Natural Gas Prices ($/Mcf) ⁽¹⁾
United States	$	2.65		$	2.23
Trinidad	2.93			2.48
Other International	4.22			3.71
Composite	2.76		(2)	2.33
Crude Oil Equivalent Volumes (MBoed)
United States	623.6			529.2
Trinidad	48.8			53.1
Other International	8.8			5.1
Total	681.2			587.4

Total MMBoe	123.3			106.3


(1)	Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements).


(2)	Includes a positive revenue adjustment of $0.40 per Mcf related to the adoption of ASU 2014-09 (see Note 1 to the Condensed Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas revenues.

-29-

Wellhead crude oil and condensate revenues for the first six months of 2018 increased $1,603 million, or 56%, to $4,479 million from $2,876 million for the same period of 2017 due primarily to a higher composite wellhead crude oil and condensate price ($1,172 million) and an increase of 49 MBbld, or 15%, in wellhead crude oil and condensate production ($431 million). Increased production was primarily due to increases in the Permian Basin and the Eagle Ford. EOG's composite wellhead crude oil and condensate price for the first six months of 2018 increased 35% to $66.16 per barrel compared to $48.85 per barrel for the same period of 2017.

NGL revenues for the first six months of 2018 increased $208 million, or 69%, to $508 million from $300 million for the same period of 2017 due primarily to a higher composite average price ($120 million) and an increase of 24 MBbld, or 29%, in NGL deliveries ($88 million) primarily in the Permian Basin and the Eagle Ford. EOG's composite NGL price for the first six months of 2018 increased 31% to $26.27 per barrel compared to $20.06 per barrel for the same period of 2017.

Wellhead natural gas revenues for the first six months of 2018 increased $146 million, or 32%, to $601 million from $455 million for the same period of 2017. The increase was due to a higher composite wellhead natural gas price ($93 million) and an increase in natural gas deliveries ($53 million). Natural gas deliveries for the first six months of 2018 increased 125 MMcfd, or 12%, compared to the same period of 2017 due primarily to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and the Eagle Ford, partially offset by lower natural gas deliveries in Trinidad. EOG's composite wellhead natural gas price for the first six months of 2018 increased 18% to $2.76 per Mcf compared to $2.33 per Mcf for the same period of 2017. The increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.40 per Mcf related to the adoption of ASU 2014-09.

During the first six months of 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $246 million compared to net gains of $71 million for the same period of 2017. During the first six months of 2018, net cash paid for settlements of financial commodity derivative contracts was $88 million compared to net cash received for settlements of financial commodity derivative contracts of $3 million for the same period of 2017. 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 2018 increased $33 million as compared to the same period of 2017 primarily due to higher margins on crude oil marketing activities.

Operating and Other Expenses. For the first six months of 2018, operating expenses of $6,080 million were $1,093 million higher than the $4,987 million incurred during the same period of 2017. The following table presents the costs per Boe for the six-month periods ended June 30, 2018 and 2017:



	Six Months Ended June 30,
	2018		2017
Lease and Well	$	4.99	$	4.81
Transportation Costs	2.88		3.43
DD&A -
Oil and Gas Properties	12.49		15.28
Other Property, Plant and Equipment	0.46		0.54
G&A	1.61		1.94
Interest Expense, Net	1.02		1.33
Total ⁽¹⁾	$	23.45	$	27.33


(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 net interest expense for the six months ended June 30, 2018, compared to the same period of 2017 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

-30-

Lease and well expenses of $615 million for the first six months of 2018 increased $104 million from $511 million for the same prior year period primarily due to higher operating and maintenance costs ($78 million), higher workover expenditures ($16 million) and higher lease and well administrative costs ($14 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($6 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs of $355 million for the first six months of 2018 decreased $10 million from $365 million for the same prior year period primarily due to decreased transportation costs in the Barnett Shale ($32 million), the Rocky Mountain area ($15 million) and the Eagle Ford ($12 million), partially offset by increased transportation costs in the Permian Basin ($52 million).

DD&A expenses for the first six months of 2018 decreased $84 million to $1,597 million from $1,681 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2018 were $84 million lower than the same prior year period. The decrease primarily reflects decreased unit rates in the United States ($366 million), partially offset by increased production in the United States ($275 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 from drilling and completions operations.

G&A expenses of $199 million for the first six months of 2018 decreased $7 million from $206 million for the same prior year period primarily due to decreased professional, legal and other services ($15 million), partially offset by increased employee-related expenses ($5 million) and information systems costs ($4 million).

Interest expense, net of $125 million for the first six months of 2018 decreased $17 million compared to the same prior year period primarily due to repayment in September 2017 of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017.

Gathering and processing costs for the first six months of 2018 increased $138 million to $211 million compared to the same prior year period primarily due to the adoption of ASU 2014-09 ($90 million) and increased operating costs in the Eagle Ford ($22 million) and the Permian Basin ($19 million).

Exploration costs of $82 million for the first six months of 2018 decreased $10 million from $92 million for the same prior year period primarily due to decreased geological and geophysical costs in the United States.

Impairments of $116 million for the first six months of 2018 were $156 million lower than impairments for the same prior year period primarily due to decreased impairments of proved properties and other assets in the United States ($129 million) and decreased amortization of unproved property costs in the United States ($27 million), which was caused by a decrease in EOG's estimates of undeveloped properties not expected to be developed before lease expiration. EOG recorded impairments of proved properties, other property, plant and equipment and other assets of $32 million and $161 million for the first six months of 2018 and 2017, respectively.

Taxes other than income for the first six months of 2018 increased $113 million to $373 million (6.7% of wellhead revenues) from $260 million (7.2% of wellhead revenues) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes in the United States as a result of increased wellhead revenues.

Other income (expense), net for the first six months of 2018 decreased $16 million compared to the same prior year period primarily due to an increase in foreign currency exchange losses ($9 million) and increased deferred compensation expense ($6 million).

EOG recognized an income tax provision of $371 million for the first six months of 2018 compared to an income tax provision of $50 million for the same period in 2017, primarily due to an increase in pretax income. The net effective tax rate for the first six months of 2018 decreased to 22% from 49% for the first six months of 2017. The lower effective tax rate is mostly due to the reduction in the U.S. federal statutory tax rate to 21% in 2018 from 35% in 2017, foreign income in the United Kingdom for which no taxes are recorded due to valuation allowances and the absence of certain 2017 state income tax apportionment changes, partially offset by a reduction in tax benefits from stock-based compensation.

-31-

Capital Resources and Liquidity

Cash Flow. The primary sources of cash for EOG during the six months ended June 30, 2018, were funds generated from operations. 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 2018, EOG's cash balance increased $174 million to $1,008 million from $834 million at December 31, 2017.

Net cash provided by operating activities of $3,494 million for the first six months of 2018 increased $1,517 million compared to the same period of 2017 primarily due to an increase in wellhead revenues ($1,956 million), a favorable change in net cash paid for income taxes ($35 million) and a favorable change in net cash paid for interest ($4 million), partially offset by an increase in cash operating expenses ($315 million), an unfavorable change in working capital ($156 million) and an increase in net cash paid for settlements of commodity derivative contracts ($91 million).

Net cash used in investing activities of $3,090 million for the first six months of 2018 increased by $1,371 million compared to the same period of 2017 due to an increase in additions to oil and gas properties ($1,095 million), a decrease in proceeds from the sales of assets ($167 million), an increase in additions to other property, plant and equipment ($57 million) and an unfavorable change in components of working capital associated with investing activities ($52 million).

Net cash used in financing activities of $228 million for the first six months of 2018 included cash dividend payments ($204 million) and purchases of treasury stock in connection with stock compensation plans ($32 million), partially offset by proceeds from stock options exercised and employee stock purchase plans ($11 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).

Total Expenditures. For the year 2018, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately $5.4 billion to $5.8 billion, excluding acquisitions and non-cash transactions. The table below sets out components of total expenditures for the six-month periods ended June 30, 2018 and 2017 (in millions):



	Six Months Ended June 30,
	2018		2017
Expenditure Category
Capital
Exploration and Development Drilling	$	2,503	$	1,447
Facilities	340		309
Leasehold Acquisitions ⁽¹⁾	172		265
Property Acquisitions ⁽²⁾	37		4
Capitalized Interest	11		14
Subtotal	3,063		2,039
Exploration Costs	82		92
Dry Hole Costs	5		—
Exploration and Development Expenditures	3,150		2,131
Asset Retirement Costs	31		24
Total Exploration and Development Expenditures	3,181		2,155
Other Property, Plant and Equipment ⁽³⁾	193		90
Total Expenditures	$	3,374	$	2,245


(1)	Leasehold acquisitions included $60 million and $154 million for the six-month periods ended June 30, 2018 and 2017, respectively, related to non-cash property exchanges.


(2)	Property acquisitions included $23 million for the six-month period ended June 30, 2018 related to non-cash property exchanges.


(3)	Other property, plant and equipment included $48 million of non-cash additions for the six-month period ended June 30, 2018 in connection with a capital lease transaction in the Permian Basin.

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Exploration and development expenditures of $3,150 million for the first six months of 2018 were $1,019 million higher than the same period of 2017 primarily due to increased exploration and drilling expenditures in the United States ($1,116 million), increased property acquisitions ($33 million) and increased facilities expenditures ($31 million), partially offset by decreased leasehold acquisitions ($93 million), decreased exploration and drilling expenditures in Trinidad ($53 million) and decreased geological and geophysical expenditures ($12 million). Exploration and development expenditures for the first six months of 2018 of $3,150 million consisted of $2,839 million in development drilling and facilities, $263 million in exploration, $37 million in property acquisitions and $11 million in capitalized interest. 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, $14 million in capitalized interest and $4 million in property acquisitions.

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

Commodity Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's Annual Report on Form 10-K for the year ended December 31, 2017, filed on February 27, 2018, 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 and Comprehensive Income. 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, 2018, as a net liability of $176 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 has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through July 27, 2018. 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.



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


2018
January 1, 2018 through August 31, 2018 (closed)	15,000	$	1.063
September 1, 2018 through December 31, 2018	15,000	1.063

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

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EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through July 27, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.



Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)


2018
January 1, 2018 through August 31, 2018 (closed)	37,000	$	3.818
September 1, 2018 through September 30, 2018	37,000	3.818
October 1, 2018 through December 31, 2018	52,000	3.911

2019
January 1, 2019 through December 31, 2019	8,000	$	5.660

Presented below is a comprehensive summary of EOG's crude oil price swap contracts through July 27, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2018
January 1, 2018 through June 30, 2018 (closed)	134,000	$	60.04
July 1, 2018 through December 31, 2018	134,000	60.04

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through July 27, 2018, 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)
2018
March 1, 2018 through August 31, 2018 (closed)	35,000	$	3.00
September 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 July 27, 2018, 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)
2018
March 1, 2018 through August 31, 2018 (closed)	120,000	$	3.38	96,000	$	2.94
September 1, 2018 through November 30, 2018	120,000	3.38		96,000	2.94

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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," "aims," "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, pay down indebtedness or pay and/or increase 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 14 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, 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 42 through 45 of EOG's Annual Report on Form 10-K for the year ended December 31, 2017, filed on February 27, 2018 (EOG's 2017 Annual Report); and (ii) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages F-30 through F-33 of EOG's 2017 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 - 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.

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, 2018 - April 30, 2018	22,366	$	112.60	—	6,386,200
May 1, 2018 - May 31, 2018	52,377	122.59		—	6,386,200
June 1, 2018 - June 30, 2018	52,182	119.15		—	6,386,200
Total	126,925	119.42		—

(1)

The 126,925 total shares for the quarter ended June 30, 2018, and the 281,481 total shares for the six months ended June 30, 2018, consist solely of 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 2018, 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

10.1	-	EOG Resources, Inc. Employee Stock Purchase Plan (As Amended and Restated Effective January 1, 2018) (incorporated by reference to Exhibit 4.4(a) to EOG's Registration Statement on Form S-8, SEC File No. 333-224466, filed April 26, 2018).

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.

*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 and Comprehensive Income - Three and Six Months Ended June 30, 2018 and 2017, (ii) the Condensed Consolidated Balance Sheets - June 30, 2018 and December 31, 2017, (iii) the Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2018 and 2017 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 2, 2018	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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