SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

For the quarterly period ended September 30, ~~2018~~2019

Commission File Number: 1-9743

(Exact name of registrant as specified in its charter)

(State or other jurisdiction

of incorporation or organization)

(Address of principal executive offices) (Zip Code)

~~713-651-7000~~713-651-7000

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	EOG	New York Stock Exchange

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 every Interactive Data File required to be submitted 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).

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☐

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).

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

(In Thousands, Except Per Share Data)

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

(In Thousands, Except Share Data)

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

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Thousands, Except Per Share Data)



	Common Stock		Additional Paid In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Common Stock Held In Treasury			Total Stockholders' Equity
Balance at June 30, 2019	$	205,809	$	5,729,318		$	(4,528	)	$	14,731,609		$	(31,932	)	$	20,630,276
Net Income	—		—			—			615,122			—			615,122
Common Stock Issued Under Stock Plans	—		—			—			—			—			—
Common Stock Dividends Declared, $0.2875 Per Share	—		—			—			(167,350		)	—			(167,350		)
Other Comprehensive Income	—		—			839			—			—			839
Change in Treasury Stock - Stock Compensation Plans, Net	—		(12,220		)	—			—			(759		)	(12,979		)
Restricted Stock and Restricted Stock Units, Net	12		(2,270		)	—			—			2,258			—
Stock-Based Compensation Expenses	—		54,670			—			—			—			54,670
Treasury Stock Issued as Compensation	—		(425		)	—			—			4,127			3,702
Balance at September 30, 2019	$	205,821	$	5,769,073		$	(3,689	)	$	15,179,381		$	(26,306	)	$	21,124,280



	Common Stock		Additional Paid In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Common Stock Held In Treasury			Total Stockholders' Equity
Balance at June 30, 2018	$	205,796	$	5,591,643		$	(17,512	)	$	11,714,656		$	(42,189	)	$	17,452,394
Net Income	—		—			—			1,190,952			—			1,190,952
Common Stock Issued Under Stock Plans	2		(2		)	—			—			—			—
Common Stock Dividends Declared, $0.22 Per Share	—		—			—			(127,504		)	—			(127,504		)
Other Comprehensive Loss	—		—			(1,946		)	—			—			(1,946		)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(7,034		)	—			—			(18,550		)	(25,584		)
Restricted Stock and Restricted Stock Units, Net	5		(7,548		)	—			—			7,543			—
Stock-Based Compensation Expenses	—		49,001			—			—			—			49,001
Treasury Stock Issued as Compensation	—		199			—			—			958			1,157
Balance at September 30, 2018	$	205,803	$	5,626,259		$	(19,458	)	$	12,778,104		$	(52,238	)	$	18,538,470

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

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Thousands, Except Per Share Data)



	Common Stock		Additional Paid In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Common Stock Held In Treasury			Total Stockholders' Equity
Balance at December 31, 2018	$	205,804	$	5,658,794		$	(1,358	)	$	13,543,130		$	(42,182	)	$	19,364,188
Net Income	—		—			—			2,098,389			—			2,098,389
Common Stock Issued Under Stock Plans	—		—			—			—			—			—
Common Stock Dividends Declared, $0.795 Per Share	—		—			—			(461,871		)	—			(461,871		)
Other Comprehensive Loss	—		—			(2,598		)	—			—			(2,598		)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(19,295		)	—			—			6,719			(12,576		)
Restricted Stock and Restricted Stock Units, Net	17		(1,886		)	—			—			1,869			—
Stock-Based Compensation Expenses	—		132,323			—			—						132,323
Treasury Stock Issued as Compensation	—		(863		)	—			—			7,288			6,425
Cumulative Effect of Adoption of ASU 2018-02, "Income Statement - Reporting Comprehensive Income (Topic 220)"	—		—			267			(267		)	—			—
Balance at September 30, 2019	$	205,821	$	5,769,073		$	(3,689	)	$	15,179,381		$	(26,306	)	$	21,124,280



	Common Stock		Additional Paid In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Common Stock Held In Treasury			Total Stockholders' Equity
Balance at December 31, 2017	$	205,788	$	5,536,547		$	(19,297	)	$	10,593,533		$	(33,298	)	$	16,283,273
Net Income	—		—			—			2,526,272			—			2,526,272
Common Stock Issued Under Stock Plans	7		(7		)	—			—			—			—
Common Stock Dividends Declared, $0.590 Per Share	—		—			—			(341,701		)	—			(341,701		)
Other Comprehensive Loss	—		—			(161		)	—			—			(161		)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(23,458		)	—			—			(23,002		)	(46,460		)
Restricted Stock and Restricted Stock Units, Net	8		(3,421		)	—			—			3,413			—
Stock-Based Compensation Expenses	—		116,290			—			—			—			116,290
Treasury Stock Issued as Compensation	—		308			—			—			649			957
Balance at September 30, 2018	$	205,803	$	5,626,259		$	(19,458	)	$	12,778,104		$	(52,238	)	$	18,538,470

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

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,~~2018, filed on February ~~27,~~26, 2019 (EOG's 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 nine months ended September 30, ~~2018,~~2019, are not necessarily indicative of the results to be expected for the full year.

Effective January 1, ~~2018,~~2019, 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 RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~EOG RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~EOG RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

EOG elected 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.adopt 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~~using 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~~with a cumulative-effect adjustment to the opening balance of retained ~~earnings.~~

As more fully discussed in Note 7 to the Consolidated Financial Statements included in EOG's ~~2017~~2018 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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Lease and Well	$	13.3	$	12.9	$	40.6	$	37.1
Gathering and Processing Costs	0.3		0.1		0.8		0.3
Exploration Costs	5.2		5.8		18.1		18.4
General and Administrative	35.9		30.2		72.8		60.5
Total	$	54.7	$	49.0	$	132.3	$	116.3

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.

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At September 30, ~~2018,~~2019, approximately ~~13.7~~7.7 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to 2008 Plan grants from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants during the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 are as follows:



	Stock Options/SARs						ESPP
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Weighted Average Fair Value of Grants	$	19.49		$	33.49		$	22.83		$	25.52
Expected Volatility	32.01		%	28.22		%	34.83		%	24.36		%
Risk-Free Interest Rate	1.69		%	2.68		%	2.28		%	1.86		%
Dividend Yield	1.39		%	0.72		%	1.04		%	0.64		%
Expected Life	5.1 years			5.0 years			0.5 years			0.5 years

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

The following table sets forth stock option and SAR transactions for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (stock options and SARs in thousands):

Outstanding at September 30 ⁽²⁾

Vested or Expected to Vest ⁽³⁾

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

At September 30, ~~2018,~~2019, unrecognized compensation expense related to non-vested stock option, SAR and ESPP grants totaled ~~$119.7~~$100.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of ~~2.3~~2.2 years.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

The following table sets forth restricted stock and restricted stock unit transactions for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (shares and units in thousands):

At September 30, ~~2018,~~2019, unrecognized compensation expense related to restricted stock and restricted stock units totaled ~~$194.5~~$227.5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of ~~2.2~~2.0 years.

Performance ~~Units and Performance Stock.~~ Units. EOG ~~has granted~~grants performance units ~~and/or performance stock (collectively, Performance Awards)~~annually to its executive officers ~~annually since 2012.~~without cost to them. As more fully discussed in the grant agreements, the performance metric applicable to the ~~Performance Awards~~performance units 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~~performance units granted could be outstanding. The fair value of the ~~Performance Awards~~performance units is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the ~~Performance Award~~performance unit grants totaled ~~$9.8~~$9.6 million and ~~$6.8~~$9.8 million for the ~~three-month periods~~three months ended September 30, 2019 and 2018, respectively, and ~~2017, respectively,~~$13.4 million and $12.1 million ~~and $8.6 million~~ for the ~~nine-month periods~~nine months ended September 30, 2019 and 2018, ~~and 2017,~~ respectively.

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the ~~Performance Awards~~performance unit transactions for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (units in thousands):

The total intrinsic value of ~~Performance Awards~~performance units released during the nine months ended September 30, 2019 and 2018, ~~and 2017~~ was ~~approximately $17.7~~$15.4 million and ~~$23.6~~$17.7 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date the ~~Performance Awards~~performance units are released.

The total intrinsic value of ~~Performance Awards~~performance units outstanding at September 30, ~~2018~~2019 and ~~2017~~2018 was approximately $44.4 million and $68.0 million, ~~and $48.6 million,~~ respectively.

At September 30, ~~2018,~~2019, unrecognized compensation expense related to ~~Performance Awards~~performance units totaled ~~$11.0~~$10.1 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of ~~1.7~~2.2 years.

3.Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the three-month and nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (in thousands, except per share data):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Numerator for Basic and Diluted Earnings Per Share -
Net Income	$	615,122	$	1,190,952	$	2,098,389	$	2,526,272
Denominator for Basic Earnings Per Share -
Weighted Average Shares	577,839		577,254		577,498		576,431
Potential Dilutive Common Shares -
Stock Options/SARs	203		1,432		371		1,317
Restricted Stock/Units and Performance Units	3,229		2,873		3,321		2,694
Denominator for Diluted Earnings Per Share -
Adjusted Diluted Weighted Average Shares	581,271		581,559		581,190		580,442
Net Income Per Share
Basic	$	1.06	$	2.06	$	3.63	$	4.38
Diluted	$	1.06	$	2.05	$	3.61	$	4.35

~~EOG RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs were ~~0.5~~6.8 million and ~~4.2~~0.5 million shares for the three months ended September 30, ~~2018~~2019 and ~~2017,~~2018, respectively, and were 6.2 million and 0.2 million ~~and 3.6 million~~ shares ~~respectively,~~ for the nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4.Supplemental Cash Flow Information

Net cash paid (received) for interest and income taxes was as follows for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (in thousands):

EOG's accrued capital expenditures at September 30, 2019 and 2018 were $568 million and ~~2017 were~~ $702 million, ~~and $545 million,~~ respectively.

Non-cash investing activities for the nine months ended September 30, 2019 and 2018, included additions of $85 million and $222 million, respectively, to EOG's oil and gas properties as a result of property exchanges. Non-cash investing activities for the nine months ended September 30, 2018 included additions ~~of $222 million to EOG's oil and gas properties as a result of property exchanges and an addition~~ of $49 million to EOG's other property, plant and equipment primarily in connection with a ~~capital~~finance lease transaction in the Permian Basin. ~~Non-cash investing activities~~

Cash paid for leases for the nine months ended September 30, ~~2017, included additions of $214 million to EOG's oil and gas properties as a result of property exchanges.~~2019, is disclosed in Note 14.

5.Segment Information

Selected financial information by reportable segment is presented below for the three-month and nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (in thousands):

Other International ⁽¹⁾

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Total assets by reportable segment are presented below at September 30, ~~2018~~2019 and December 31, ~~2017~~2018 (in thousands):

Other International ⁽¹⁾

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 nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (in thousands):

Liabilities Settled ⁽¹⁾

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.

~~EOG RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

7.Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the nine-month period ended September 30, ~~2018,~~2019, are presented below (in thousands):



	Nine Months Ended September 30, 2019
Balance at January 1	$	4,121
Additions Pending the Determination of Proved Reserves	48,917
Reclassifications to Proved Properties	(6,286		)
Costs Charged to Expense	(22,421		)
Balance at September 30	$	24,331

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Nine Months Ended
September 30, 2018
Balance at January 1 $ 2,167
Additions Pending the Determination of Proved Reserves 6,497
Reclassifications to Proved Properties (5,346 )
Costs Charged to Expense (433 )
Balance at September 30 $ 2,885

At September 30, ~~2018,~~2019, 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.

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 nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, EOG's total costs recognized for these pension plans were ~~$30~~$34 million and ~~$27~~$30 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. EOG had 0 outstanding commercial paper borrowings at September 30, 2019 and December 31, 2018 and did not utilize any such borrowings during the nine months ended September 30, 2019. During the nine months ended September 30, 2018, ~~and 2017,~~ EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. ~~At September 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 $11 million ~~and $9 million~~ during the nine months ended September 30, ~~2018 and 2017, respectively.~~2018. The weighted average interest rate for commercial paper borrowings during the nine months ended September 30, 2018, ~~and 2017,~~ was 1.97% ~~and 1.39%, respectively.~~.

On ~~October 1, 2018,~~June 3, 2019, EOG repaid upon maturity the ~~$350~~$900 million aggregate principal amount of its ~~6.875%~~5.625% Senior Notes due ~~2018.~~2019.

On June 27, 2019, EOG ~~currently has~~entered into a new $2.0 billion senior unsecured Revolving Credit Agreement ~~(Agreement)~~(New Facility) with domestic and foreign ~~lenders.~~lenders (Banks). The New Facility replaced EOG’s $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, with domestic and foreign lenders (2015 Facility), which had a scheduled maturity date of July 21, 2020 and which was terminated by EOG (without penalty), effective as of June 27, 2019, in connection with the completion of the New Facility.

The New Facility has a scheduled maturity date of ~~July 21, 2020,~~June 27, 2024, 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. The New Facility (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions, and (ii) includes a swingline subfacility and a letter of credit subfacility. Advances under the ~~Agreement~~New Facility will accrue interest based, at ~~EOG's~~EOG’s option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar ~~rate)~~Rate) or the ~~base rate~~Base Rate (as defined in the ~~Agreement)~~New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG’s credit rating for its senior unsecured long-term debt at the applicable time.

Consistent with the terms of the 2015 Facility, the New Facility contains representations, warranties, covenants and events of default that we believe are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of total debt-to-total capitalization (as such terms are defined in the New Facility) of no greater than 65%. At September 30, ~~2018 and December 31, 2017, there~~2019, EOG was in compliance with this financial covenant.

There were no0 borrowings or letters of credit outstanding under the ~~Agreement.~~2015 Facility as of (i) December 31, 2018 or (ii) the June 27, 2019 effective date of the closing of the New Facility and termination of the 2015 Facility. Further, at September 30, 2019, there were 0 borrowings or letters of credit outstanding under the New Facility. The Eurodollar ~~rate~~Rate and Base Rate (inclusive of the applicable ~~base rate,~~margin), had there been any amounts borrowed under the ~~Agreement~~New Facility at September 30, ~~2018,~~2019, would have been ~~3.16%~~2.92% and ~~5.25%~~5.0%, respectively.

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Common Stock. On ~~August~~May 2, ~~2018,~~2019, EOG's Board of Directors increased the quarterly cash dividend on the common stock from the previous ~~$0.1850~~$0.22 per share to ~~$0.22~~$0.2875 per share, effective beginning with the dividend ~~to be~~ paid on ~~October~~July 31, ~~2018,~~2019, to stockholders of record as of ~~October~~July 17, ~~2018.~~2019.

~~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~~2018 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 September 30, ~~2018~~2019 and December 31, ~~2017~~2018 (in ~~millions)~~thousands):



	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At September 30, 2019
Financial Assets:
Natural Gas Swaps	$	—	$	3,629	$	—	$	3,629
Crude Oil Swaps	—		119,088		—		119,088
Crude Oil Basis Swaps	—		1,162		—		1,162
Natural Gas Basis Swaps	—		230		—		230
Financial Liabilities:
Crude Oil Basis Swaps	$	—	$	1,482	$	—	$	1,482
Natural Gas Basis Swaps	—		21		—		21

At December 31, 2018
Financial Assets:
Crude Oil Basis Swaps	$	—	$	23,806	$	—	$	23,806

Fair Value Measurements Using:

Quoted
Prices in
Active
Markets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
Total
At September 30, 2018

Financial Assets:

Crude Oil Basis Swaps $ —
$ 35
$ —
$ 35
Financial Liabilities:
Crude Oil Swaps $ —
$ 159
$ —
$ 159
Crude Oil Basis Swaps —
2
—
2

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 ~~$165~~$472 million were written down to their fair value of ~~$131~~$340 million, resulting in pretax impairment charges of ~~$34~~$132 million for the nine months ended September 30, ~~2018.~~2019. Included in the ~~$34~~$132 million pretax impairment charges are ~~$21~~$89 million for a commodity price-related write-down of other assets.

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

Fair Value of Debt.At September 30, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively, EOG had outstanding ~~$6,390~~$5,140 million and $6,040 million aggregate principal amount of senior notes, which had estimated fair values at such dates of approximately ~~$6,400~~$5,453 million and ~~$6,602~~$6,027 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.

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~~2018 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 nine months ended September 30, ~~2018.~~2019. 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)


2019
January 1, 2019 through October 31, 2019 (closed)	20,000	$	1.075
November 1, 2019 through December 31, 2019	20,000	1.075

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

2018
January 1, 2018 through October 31, 2018 (closed) 15,000
$ 1.063
November 1, 2018 through December 31, 2018 15,000
1.063

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

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 nine months ended September 30, ~~2018.~~2019. 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)


2019
January 1, 2019 through October 31, 2019 (closed)	13,000	$	5.572
November 1, 2019 through December 31, 2019	13,000	5.572

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

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

2019
January 1, 2019 through December 31, 2019 10,000
$ 5.558

~~EOG RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the nine months ended September 30, ~~2018,~~2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2019
April 2019 (closed)	25,000	$	60.00
May 1, 2019 through September 30, 2019 (closed)	150,000	62.50
October 1, 2019 through December 31, 2019	150,000	62.50

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts for the nine months ended September 30, 2019. The weighted average price differential expressed in dollars per million British thermal units ($/MMBtu) represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtu per day (MMBtud) covered by the basis swap contracts.



Rockies Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)


2020
January 1, 2020 through December 31, 2020	14,000	$	0.55

Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the nine months ended September 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 October 31, 2018 (closed) 35,000
$ 3.00
November 2018 35,000
3.00

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

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the nine months ended September 30, 2018,2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.



Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2019
April 1, 2019 through October 31, 2019 (closed)	250,000	$	2.90

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 October 31, 2018 (closed) 120,000
$ 3.38
96,000
$ 2.94
November 2018 120,000
3.38
96,000
2.94

~~EOG RESOURCES, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)~~

~~(Unaudited)~~

The following table sets forth the amounts and classification of EOG's outstanding financial derivative instruments at September 30, ~~2018~~2019 and December 31, ~~2017.~~2018. 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)~~thousands):


		Fair Value at					Fair Value at
Description	Location on Balance Sheet	September 30, 2018		December 31, 2017		Location on Balance Sheet	September 30, 2019		December 31, 2018
Asset Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities	$	2	$	8	Assets from Price Risk Management Activities ⁽¹⁾	$	122,627	$	23,806
Noncurrent portion	Other Assets	5		—
Liability Derivatives
Crude oil and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities ⁽¹⁾	$	133	$	50
Noncurrent portion	Other Liabilities	—		7		Other Liabilities	$	21	$	—


(1)	The current portion of ~~Liabilities~~Assets from Price Risk Management Activities consists of gross ~~liabilities~~assets of ~~$161~~$124 million, partially offset by gross ~~assets~~liabilities of ~~$28~~$1 million at September 30, ~~2018, and gross liabilities of $55 million, partially offset by gross assets of $5 million at December 31, 2017.~~2019.

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(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~~that 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~~asset position at September 30, ~~2018~~2019 and December 31, ~~2017.~~2018. EOG had no0 collateral posted ~~and~~or held ~~no collateral~~ at September 30, ~~2018 and~~2019, or at December 31, ~~2017.~~2018.

13. Acquisitions and Divestitures

During the nine months ended September 30, 2019, EOG paid cash for property acquisitions of $311 million in the United States. Additionally, during the nine months ended September 30, 2019, EOG recognized net gains on asset dispositions of $4 million and received proceeds of approximately $35 million. During the nine months ended September 30, 2018, EOG recognized a net ~~gain~~gains on asset dispositions of $95 million, primarily due to non-cash ~~property~~ exchanges of unproved leasehold in Texas, New Mexico and Wyoming and received proceeds of approximately $12 million. ~~Additionally,~~

14. Leases

In the ordinary course of business, EOG enters into contracts for drilling, fracturing, compression, real estate and other services which contain equipment and other assets and that meet the definition of a lease under ASU 2016-02. The lease term for these contracts, which includes any renewals at EOG's option that are reasonably certain to be exercised, ranges from one month to 30 years. ROU assets and related liabilities are recognized on commencement date on the Condensed Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the ~~third quarter~~contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of ~~2018, EOG's wholly-owned subsidiary signed~~the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a ~~share purchase~~collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Condensed Consolidated Balance Sheets, but instead are disclosed as short-term lease cost.

EOG has elected not to separate non-lease components from all leases, excluding those for fracturing services, real estate and ~~sale agreement~~salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs.

Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Condensed Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the Accounting Standards Codification. Variable lease cost represents costs incurred above the contractual minimum payments for operating and finance leases. The components of lease cost for the ~~sale of all of its interest in EOG Resources United Kingdom Limited, which is expected to close in the fourth quarter of 2018. At~~three month and nine month periods ended September 30, ~~2018,~~2019, were as follows (in millions):



	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating Lease Cost	$	138	$	391
Finance Lease Cost:
Amortization of Lease Assets	3		10
Interest on Lease Liabilities	—		1
Variable Lease Cost	39		167
Short-Term Lease Cost	67		295
Total Lease Cost	$	247	$	864

EOG RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table sets forth the ~~book value~~amounts and classification of ~~the~~EOG's outstanding ROU assets ~~held~~and related lease liabilities and supplemental information at September 30, 2019 (in millions, except lease terms and discount rates):



Description	Location on Balance Sheet	Amount
Assets
Operating Leases	Other Assets	$	842
Finance Leases	Property, Plant and Equipment, Net ⁽¹⁾	56
Total		$	898

Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	384
Finance Leases	Current Portion of Long-Term Debt	15
Long-Term
Operating Leases	Other Liabilities	485
Finance Leases	Long-Term Debt	46
Total		$	930


(1)	Finance lease assets are recorded net of accumulated amortization of $57 million at September 30, 2019.



	Nine Months Ended September 30, 2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	3.2
Finance Leases	4.9

Weighted Average Discount Rate:
Operating Leases	3.5	%
Finance Leases	3.0	%

Cash paid for ~~sale and the related liabilities were $235 million and $65 million, respectively. During~~leases was as follows for the nine months ended September 30, ~~2017,~~2019 (in millions):



	Nine Months Ended September 30, 2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	162
Repayment of Operating Lease Liabilities Associated with Investing Activities	225
Repayment of Finance Lease Liabilities	10

Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized ~~a net loss on asset dispositions~~operating lease ROU assets of ~~$(34)~~$566 million. Non-cash leasing activities for the nine months ended September 30, 2019, included the addition of $703 million of operating leases.

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Concluded)

(Unaudited)

At September 30, 2019, the future minimum lease payments under non-cancellable leases were as follows (in millions):



	Operating Leases		Finance Leases
October 1, 2019 to December 31, 2019	$	116	$	3
2020	377		15
2021	198		15
2022	118		12
2023	50		8
2024 and Beyond	64		14
Total Lease Payments	923		67
Less: Discount to Present Value	54		6
Total Lease Liabilities	869		61
Less: Current Portion of Lease Liabilities	384		15
Long-Term Lease Liabilities	$	485	$	46

At September 30, 2019, EOG had additional leases of $675 million, of which $24 million, $446 million and ~~received proceeds~~$205 million were expected to commence in the remainder of ~~approximately $192 million primarily from~~2019 and in 2020 and 2021, respectively, with lease terms of one month to 10 years.

At December 31, 2018 and prior to the ~~sale~~adoption of ~~producing assets, unproved leasehold~~ASU 2016-02 and other ~~property, plant~~related ASUs, the future minimum commitments under non-cancellable leases, including non-lease components and ~~equipment in Oklahoma and Texas.~~excluding contracts with lease terms of less than 12 months, were as follows (in millions):



	Operating Leases		Finance Leases
2019	$	380	$	15
2020	213		15
2021	86		15
2022	39		12
2023	30		8
2024 and Beyond	62		14
Total Lease Payments	$	810	$	79

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~~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 primarily 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 efficient, safe and environmentally responsible 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~~2019 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 nine months of ~~2018,~~2019, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were ~~$66.79~~$57.06 per barrel and ~~$2.86~~$2.66 per million British thermal units (MMBtu), respectively, representing ~~an increase~~decreases of ~~35%~~15% and ~~a decrease of 8%~~7%, respectively, from the average NYMEX prices for the same period in ~~2017.~~2018. 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~~2019 drilling and completion plans, EOG expects ~~2018~~both its 2019 total production and total crude oil production to increase as compared to ~~2017.~~2018.

During the first nine months of ~~2018,~~2019, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to evaluate certain potential crude oil and liquids-rich natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGL production accounted for approximately 77% of EOG's United States production during both the first nine months of 2019 and 2018, ~~and 2017.~~respectively. During the first nine months of ~~2018,~~2019, 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~~Heritage Petroleum Company ~~of Trinidad and Tobago~~ Limited. ~~EOG has 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.~~ In the third quarter of ~~2018, EOG's wholly-owned subsidiary signed a share purchase and sale agreement for~~2019, EOG drilled two net wells, one of which was an unsuccessful exploratory well. During the ~~sale~~remainder of ~~all of its interest in~~2019, EOG ~~Resources United Kingdom Limited, which is expected~~plans to ~~close in the fourth quarter of 2018.~~drill two additional net wells.

Other International. 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~~drilled two wells in the ~~Bajiaochang Field. The~~first nine months of 2019 to complete the drilling program started in 2018. Additionally, EOG completed two drilled uncompleted wells from 2018 in 2019. All natural gas produced from the ~~Bajiaochang~~Baijaochang Field is sold under a long-term contract to PetroChina Company Limited. EOG commenced a seven-well drilling program during the third quarter of 2018 and completed one of these wells in October 2018. This drilling program is expected to continue.PetroChina.

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 ~~26%~~20% at September 30, ~~2018~~2019 and ~~28%~~24% at December 31, ~~2017.~~2018. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On ~~October 1, 2018,~~June 3, 2019, EOG repaid upon maturity the ~~$350~~$900 million aggregate principal amount of its ~~6.875%~~5.625% Senior Notes due ~~2018.~~2019.

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, which had a scheduled maturity date of July 21, 2020. The New Facility has a scheduled maturity date of June 27, 2024, 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. The New Facility (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions, and (ii) includes a swingline subfacility and a letter of credit subfacility.

Effective January 1, 2019, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs resulted in the recognition of right-of-use assets and related lease liabilities representing the obligation to make lease payments for certain lease transactions and the disclosure of additional leasing information. The adoption of ASU 2016-02 and other related ASUs resulted in a significant increase to assets and liabilities related to operating leases on the Condensed Consolidated Balance Sheet at September 30, 2019. Financial results prior to January 1, 2019, are unchanged. See Note 1 "Summary of Significant Accounting Policies" and Note 14 "Leases" to EOG's Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Total anticipated ~~2018~~2019 capital expenditures are estimated to range from approximately ~~$5.8~~$6.2 billion to ~~$6.0~~$6.4 billion, excluding acquisitions and non-cash transactions. The majority of ~~2018~~2019 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, ~~and other uncommitted credit facilities,~~ bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility described above, joint development agreements and similar ~~arrangements~~agreements and equity and debt offerings.

Management continues to believe EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.

Results of Operations

The following review of operations for the three months and nine months ended September 30, ~~2018~~2019 and ~~2017~~2018 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 September 30, ~~2018~~2019 vs. Three Months Ended September 30, ~~2017~~2018

Operating Revenues. During the third quarter of ~~2018~~2019, operating revenues ~~increased $2,137~~decreased $479 million, or ~~81%~~10%, to ~~$4,782~~$4,303 million from ~~$2,645~~$4,782 million for the same period of ~~2017~~2018. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, for the third quarter of ~~2018~~ ~~increased $1,470~~2019 decreased $468 million, or ~~79%~~14%, to ~~$3,321~~$2,853 million from ~~$1,851~~$3,321 million for the same period of ~~2017~~2018. EOG recognized net ~~losses~~gains on the mark-to-market of financial commodity derivative contracts of ~~$52~~$86 million for the third quarter of ~~2018~~2019 compared to net losses of $7$52 million for the same period of ~~2017~~2018. Gathering, processing and marketing revenues for the third quarter of ~~2018~~ ~~increased $577~~2019 decreased $27 million, or ~~74%~~2%, to ~~$1,361~~$1,334 million from ~~$784~~$1,361 million for the same period of ~~2017~~2018. Net ~~gains~~losses on asset dispositions were ~~$116~~$1 million for the third quarter of ~~2018~~2019 compared to net ~~losses~~gains of $8$116 million for the same period of ~~2017.~~2018.

Wellhead volume and price statistics for the three-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 were as follows:


	Three Months Ended September 30,					Three Months Ended September 30,
	2018			2017		2019		2018
Crude Oil and Condensate Volumes (MBbld) ⁽¹⁾
United States	409.2			327.1		463.2		409.2
Trinidad	0.8			0.8		0.8		0.8
Other International ⁽²⁾	5.0			—		0.1		5.0
Total	415.0			327.9		464.1		415.0
Average Crude Oil and Condensate Prices ($/Bbl) ⁽³⁾
United States	$	69.53		$	48.06	$	56.67	$	69.53
Trinidad	61.71			39.42		48.36		61.71
Other International ⁽²⁾	72.81			—		59.87		72.81
Composite	69.55			48.11		56.66		69.55
Natural Gas Liquids Volumes (MBbld) ⁽¹⁾
United States	127.8			87.4		141.3		127.8
Other International ⁽²⁾	—			—		—		—
Total	127.8			87.4		141.3		127.8
Average Natural Gas Liquids Prices ($/Bbl) ⁽³⁾
United States	$	30.09		$	22.38	$	12.67	$	30.09
Other International ⁽²⁾	—			—		—		—
Composite	30.09			22.38		12.67		30.09
Natural Gas Volumes (MMcfd) ⁽¹⁾
United States	948			748		1,079		948
Trinidad	260			323		260		260
Other International ⁽²⁾	28			25		34		28
Total	1,236			1,096		1,373		1,236
Average Natural Gas Prices ($/Mcf) ⁽³⁾
United States	$	2.67		$	2.20	$	1.97	$	2.67
Trinidad	2.88			2.04		2.52		2.88
Other International ⁽²⁾	3.83			3.74		4.25		3.83
Composite	2.74		⁽⁴⁾	2.19		2.13		2.74
Crude Oil Equivalent Volumes (MBoed) ⁽⁵⁾⁽⁴⁾
United States	695.0			539.2		784.3		695.0
Trinidad	44.1			54.6		44.1		44.1
Other International ⁽²⁾	9.7			4.3		5.8		9.7
Total	748.8			598.1		834.2		748.8

Total MMBoe ⁽⁵⁾⁽⁴⁾	68.9			55.0		76.7		68.9

Wellhead crude oil and condensate revenues for the third quarter of ~~2018~~ ~~increased $1,204~~2019 decreased $236 million, or ~~83%~~9%, to ~~$2,655~~$2,419 million from ~~$1,451~~$2,655 million for the same period of ~~2017~~2018. The ~~increase~~decrease was due to a ~~higher~~lower composite ~~wellhead crude oil and condensate~~average price ($~~819~~550 million) ~~and~~, partially offset by an increase of 8749 MBbld, or ~~27%~~12%, in wellhead crude oil and condensate production ($~~385~~314 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 third quarter of ~~2018~~ ~~increased 45%~~2019 decreased 19% to ~~$69.55~~$56.66 per barrel compared to ~~$48.11~~$69.55 per barrel for the same period of ~~2017~~2018.

NGL revenues for the third quarter of ~~2018~~ ~~increased $174~~2019 decreased $189 million, or ~~96%~~53%, to ~~$354~~$165 million from ~~$180~~$354 million for the same period of ~~2017~~2018 due to a ~~higher~~lower composite average price ($91226 million) ~~and~~, partially offset by an increase of 4014 MBbld, or ~~46%~~11%, in production ($8337 million). Increased production was primarily in the Permian ~~Basin and the Eagle Ford.~~Basin. EOG's composite NGL price for the third quarter of ~~2018 increased 34%~~2019 decreased 58% to ~~$30.09~~$12.67 per barrel compared to ~~$22.38~~$30.09 per barrel for the same period of ~~2017.~~2018.

Wellhead natural gas revenues for the third quarter of ~~2018~~ ~~increased $92~~2019 decreased $42 million, or ~~41%~~14%, to ~~$312~~$270 million from ~~$220~~$312 million for the same period of ~~2017~~2018. The ~~increase~~decrease was due to a ~~higher~~lower average composite ~~wellhead natural gas~~ price ($6376 million) ~~and~~, partially offset by an increase in natural gas deliveries ($2834 million). Natural gas deliveries for the third quarter of ~~2018~~2019 increased ~~140~~137 MMcfd, or ~~13%~~11%, compared to the same period of ~~2017~~2018 due primarily to higher deliveries in the United States ~~primarily~~ resulting from increased production of associated natural gas from the Permian Basin and ~~the Eagle Ford and~~ higher natural gas volumes ~~from the Marcellus Shale,~~in South Texas, partially offset by lower ~~natural gas deliveries~~volumes in ~~Trinidad.~~the Marcellus Shale. EOG's composite wellhead natural gas price for the third quarter of ~~2018~~ ~~increased 25%~~2019 decreased 22% to ~~$2.74~~$2.13 per Mcf compared to ~~$2.19~~$2.74 per Mcf for the same period of ~~2017~~2018. ~~This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.49 per Mcf related to the adoption of ASU 2014-09.~~

During the third quarter of ~~2018~~2019, EOG recognized net ~~losses~~gains on the mark-to-market of financial commodity derivative contracts of ~~$52~~$86 million compared to $7net losses of $52 million for the same period of ~~2017~~2018. During the third quarter of ~~2018,~~2019, net cash ~~paid for~~received from settlements of financial commodity derivative contracts was ~~$92~~$108 million compared to net cash ~~received~~paid of $2$92 million for the same period of ~~2017.~~2018.

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 third quarter of ~~2018~~ ~~increased~~2019 decreased $43 million as compared to the same period of ~~2017~~2018 primarily due to ~~higher~~lower margins on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.

Operating and Other Expenses.For the third quarter of ~~2018,~~2019, operating expenses of ~~$3,275~~$3,475 million were ~~$845~~$200 million higher than the ~~$2,430~~$3,275 million incurred during the third quarter of ~~2017.~~2018. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended September 30, ~~2018~~2019 and ~~2017:~~2018:

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 September 30, ~~2018,~~2019, compared to the same period of ~~2017,~~2018, 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 ~~$322~~$349 million for the third quarter of ~~2018~~2019 increased ~~$70~~$27 million from ~~$252~~$322 million for the same prior year period primarily due to increased operating and maintenance costs ($~~44 million), workover expenditures ($19~~33 million) and lease and well administrative expenses ($149 million)~~, all~~ in the United States, partially offset by decreased ~~operating and maintenance costs~~workover expenditures in the United ~~Kingdom~~States ($69 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 $196 million for the third quarter of 2018 increased $12 million from $184 million for the same prior year period primarily due to increased transportation costs in the Permian Basin ($33 million), partially offset by decreased transportation costs in the Barnett Shale ($11 million), the Rocky Mountain area ($5 million) and the Eagle Ford ($4 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 third quarter of ~~2018~~2019 increased ~~$72~~$36 million to ~~$918~~$954 million from ~~$846~~$918 million for the same prior year period. DD&A expenses associated with oil and gas properties for the third quarter of ~~2018~~2019 were ~~$70~~$58 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($~~224~~109 million), partially offset by ~~decreased~~lower unit rates in the United States ($~~155~~42 million). ~~DD&A unit~~Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower ~~cost~~costs as a result of increased ~~efficiencies from drilling and completions operations.~~efficiencies.

~~Interest expense, net~~G&A expenses of ~~$64~~$136 million for the third quarter of ~~2018~~2019 increased $25 million from $111 million for the same prior year period primarily due to increased employee-related and information systems costs resulting from expanded operations.

Interest expense, net of $40 million for the third quarter of 2019 decreased $5$24 million compared to the same prior year period primarily due to repayment in ~~September 2017~~June 2019 of the ~~$600~~$900 million aggregate principal amount of ~~5.875%~~5.625% Senior Notes due ~~2017.~~2019 ($13 million), repayment in October 2018 of the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 ($6 million) and higher capitalized interest ($4 million).

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,~~as well as natural gas processing fees and certain NGL fractionation fees from third parties. EOG pays third parties to process ~~a portion~~the majority 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.~~

Gathering and processing costs increased ~~$81~~$14 million to ~~$114~~$128 million for the third quarter of ~~2018~~2019 compared to ~~$33~~$114 million for the same prior year period primarily due to ~~the adoption of ASU 2014-09 ($57 million) and~~ increased operating costs and fees in ~~the United Kingdom ($21 million) and~~ the Permian Basin ($713 million) and the Eagle Ford ($5 million), partially offset by decreased operating costs in the ~~Barnett Shale~~United Kingdom ($7 ~~million).~~million ) due to the sale of operations in the fourth quarter of 2018.

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 ~~$45~~$105 million for the third quarter of ~~2018~~2019 were $9$61 million ~~lower~~higher than impairments for the same prior year period primarily due to ~~decreased~~increased impairments of proved properties in the United States ($40 million), and increased amortization of unproved property costs in the United States ($21 million), which ~~was~~were caused by ~~a decrease~~an increase 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 $1$41 million and $3$1 million for the third ~~quarter~~quarters of ~~2018~~2019 and ~~2017,~~2018, 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 third quarter of ~~2018 increased $83~~2019 decreased $6 million to ~~$209~~$203 million ~~(6.3%~~(7.1% of wellhead revenues) ~~compared to $126~~from $209 million ~~(6.8%~~(6.3% of wellhead revenues) for the same prior year period. The ~~increase~~decrease in taxes other than income was primarily due to ~~increases in~~decreased severance/production taxes in the United States ~~as a result of increased wellhead revenues~~ ($6813 million) and ~~increased~~an increase in credits available to EOG in the third quarter of 2019 for state incentive severance tax rate reductions ($3 million), partially offset by higher payroll taxes in Trinidad ($8 million) and an increase in ad valorem/property taxes in the United States ($134 million).

Other income, net of $9 million for the third quarter of 2019 increased $6 million compared to the same prior year period primarily due to a decrease in deferred compensation expense.

EOG recognized an income tax provision of $182 million for the third quarter of 2019 compared to an income tax provision of $255 million for the third quarter of 2018, ~~compared to an income tax provision of $45 million in the third quarter of 2017,~~ primarily due to ~~an increase in~~decreased pretax ~~income.~~income, partially offset by the absence of tax benefits from certain tax reform measurement-period adjustments. The net effective tax rate for ~~2018 decreased~~2019 increased to 23% from 18% ~~from 31%~~ in ~~2017.~~2018. The ~~lower~~higher effective tax rate is mostly due to the ~~reduction in the U.S. federal statutory~~absence of tax ~~rate to 21% in 2018 from 35% in 2017 and an overall net tax benefit~~benefits from certain tax reform measurement-period ~~adjustments primarily related to the repatriation tax, partially offset by a reduction in tax benefits from stock-based compensation.~~adjustments.

Nine Months Ended September 30, ~~2018~~2019 vs. Nine Months Ended September 30, ~~2017~~2018

Operating Revenues. During the first nine months of ~~2018~~2019, operating revenues increased ~~$4,833~~$359 million, or ~~61%~~3%, to ~~$12,701~~$13,060 million from ~~$7,868~~$12,701 million for the same period of ~~2017~~2018. Total wellhead revenues for the first nine months of ~~2018~~ ~~increased $3,426~~2019 decreased $316 million, or ~~62%~~4%, to ~~$8,908~~$8,592 million from ~~$5,482~~$8,908 million for the same period of ~~2017~~2018. During the first nine months of ~~2018~~2019, EOG recognized net ~~losses~~gains on the mark-to-market of financial commodity derivative contracts of ~~$298~~$243 million compared to net ~~gains~~losses of ~~$65~~$298 million for the same period of ~~2017~~2018. Gathering, processing and marketing revenues for the first nine months of ~~2018~~2019 increased ~~$1,609~~$222 million, or ~~70%~~6%, to ~~$3,899~~$4,121 million from ~~$2,290~~$3,899 million for the same period of ~~2017~~2018. Net gains on asset dispositions were ~~$95~~$4 million for the first nine months of ~~2018~~2019 compared to net ~~losses~~gains of ~~$34~~$95 million for the same period of ~~2017.~~2018.

Wellhead volume and price statistics for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 were as follows:


	Nine Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2019		2018
Crude Oil and Condensate Volumes (MBbld)
United States	382.9			324.3		451.2		382.9
Trinidad	0.8			0.8		0.7		0.8
Other International	4.1			1.0		0.1		4.1
Total	387.8			326.1		452.0		387.8
Average Crude Oil and Condensate Prices ($/Bbl) ⁽¹⁾
United States	$	67.35		$	48.61	$	57.95	$	67.35
Trinidad	58.91			40.24		47.26		58.91
Other International	71.83			51.55		58.43		71.83
Composite	67.38			48.60		57.93		67.38
Natural Gas Liquids Volumes (MBbld)
United States	113.9			84.3		130.8		113.9
Other International	—			—		—		—
Total	113.9			84.3		130.8		113.9
Average Natural Gas Liquids Prices ($/Bbl)
United States	$	27.71		$	20.87	$	15.96	$	27.71
Other International	—			—		—		—
Composite	27.71			20.87		15.96		27.71
Natural Gas Volumes (MMcfd)
United States	905			744		1,043		905
Trinidad	278			317		267		278
Other International	31			22		36		31
Total	1,214			1,083		1,346		1,214
Average Natural Gas Prices ($/Mcf) ⁽¹⁾
United States	$	2.66		$	2.22	$	2.23	$	2.66
Trinidad	2.91			2.33		2.71		2.91
Other International	4.10			3.72		4.29		4.10
Composite	2.75		(2)	2.28		2.38		2.75
Crude Oil Equivalent Volumes (MBoed)
United States	647.6			532.6		755.8		647.6
Trinidad	47.2			53.6		45.1		47.2
Other International	9.2			4.8		6.2		9.2
Total	704.0			591.0		807.1		704.0

Total MMBoe	192.2			161.3		220.3		192.2

Wellhead crude oil and condensate revenues for the first nine months of ~~2018~~2019 increased ~~$2,807~~$14 million ~~or 65%,~~ to ~~$7,134~~$7,148 million from ~~$4,327~~$7,134 million for the same period of ~~2017~~2018 due to ~~a higher composite wellhead crude oil and condensate price ($1,989 million) and~~ an increase of 6264 MBbld, or ~~19%~~17%, in wellhead crude oil and condensate production ($~~818~~1,185 million), partially offset by a lower composite average price ($1,171 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 nine months of ~~2018~~ ~~increased 39%~~2019 decreased 14% to ~~$67.38~~$57.93 per barrel compared to ~~$48.60~~$67.38 per barrel for the same period of ~~2017~~2018.

NGL revenues for the first nine months of ~~2018~~ ~~increased $382~~2019 decreased $292 million, or ~~80%~~34%, to ~~$862~~$570 million from ~~$480~~$862 million for the same period of ~~2017~~2018 due to a ~~higher~~lower composite average price ($~~213~~420 million) ~~and~~, partially offset by an increase of 3017 MBbld, or ~~35%~~15%, in NGL deliveries ($~~169~~128 million). Increased production was primarily in the Permian ~~Basin and the Eagle Ford.~~Basin. EOG's composite NGL price for the first nine months of ~~2018~~ ~~increased 33%~~2019 decreased 42% to ~~$27.71~~$15.96 per barrel compared to ~~$20.87~~$27.71 per barrel for the same period of ~~2017~~2018.

Wellhead natural gas revenues for the first nine months of ~~2018~~ ~~increased $237~~2019 decreased $38 million, or ~~35%~~4%, to ~~$912~~$874 million from ~~$675~~$912 million for the same period of ~~2017~~2018. The ~~increase~~decrease was due to a ~~higher~~lower composite wellhead natural gas price ($~~156~~140 million) ~~and~~, partially offset by an increase in natural gas deliveries ($81102 million). Natural gas deliveries for the first nine months of ~~2018~~2019 increased ~~131~~132 MMcfd, or ~~12%~~11%, compared to the same period of ~~2017~~2018 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 and~~ higher natural gas volumes from ~~the Marcellus Shale, partially offset by lower natural gas deliveries in Trinidad.~~South Texas. EOG's composite wellhead natural gas price for the first nine months of ~~2018~~ ~~increased 21%~~2019 decreased 14% to ~~$2.75~~$2.38 per Mcf compared to ~~$2.28~~$2.75 per Mcf for the same period of ~~2017~~2018. ~~The increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.43 per Mcf related to the adoption of ASU 2014-09.~~

During the first nine months of ~~2018~~2019, EOG recognized net ~~losses~~gains on the mark-to-market of financial commodity derivative contracts of ~~$298~~$243 million compared to net ~~gains~~losses of ~~$65~~$298 million for the same period of ~~2017~~2018. During the first nine months of ~~2018~~2019, net cash received from settlements of financial commodity derivative contracts was $140 million compared to net cash paid for settlements of financial commodity derivative contracts ~~was~~of $180 ~~million compared to net cash received for settlements of financial commodity derivative contracts of $5~~ million for the same period of ~~2017. The net cash received for financial commodity derivative contracts during the first nine months of 2017 included certain early-terminated crude oil price swaps.~~2018.

Gathering, processing and marketing revenues less marketing costs for the first nine months of ~~2018~~ ~~increased $76~~2019 decreased $38 million as compared to the same period of ~~2017~~2018 primarily due to ~~higher~~lower margins on crude oil marketing activities, partially offset by higher margins on natural gas marketing activities.

Operating and Other Expenses. For the first nine months of ~~2018,~~2019, operating expenses of ~~$9,355~~$10,224 million were ~~$1,938~~$869 million higher than the ~~$7,417~~$9,355 million incurred during the same period of ~~2017.~~2018. The following table presents the costs per Boe for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017:~~2018:

The primary factors impacting the cost components of per-unit rates of lease and well, DD&A, G&A and net interest expense for the nine months ended September 30, ~~2018,~~2019, compared to the same period of ~~2017~~2018 are set forth below. See "Operating Revenues" above for a discussion of wellhead volumes.

Lease and well expenses of ~~$936~~$1,032 million for the first nine months of ~~2018~~2019 increased ~~$173~~$96 million from ~~$763~~$936 million for the same prior year period primarily due to higher operating and maintenance costs ($~~122~~81 million), ~~higher workover expenditures ($34 million) and~~ higher lease and well administrative costs ($2821 million) and higher workover expenditures ($8 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($1311 million). due to the sale of operations in the fourth quarter of 2018. Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

DD&A expenses for the first nine months of ~~2018 decreased $13~~2019 increased $275 million to ~~$2,515~~$2,790 million from ~~$2,528~~$2,515 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first nine months of ~~2018~~2019 were ~~$14~~$299 million ~~lower~~higher than the same prior year period. The ~~decrease~~increase primarily reflects ~~decreased~~increased production in the United States ($384 million), partially offset by lower unit rates in the United States ($~~522 million), partially offset by increased production in the United States ($501~~56 million). ~~DD&A unit~~Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower ~~cost~~costs as a result of increased ~~efficiencies from drilling and completions operations.~~efficiencies.

G&A expenses of ~~$310~~$364 million for the first nine months of ~~2018 decreased $7~~2019 increased $54 million from ~~$317~~$310 million for the same prior year period primarily due to ~~decreased professional, legal and other services ($17 million), partially offset by~~ increased employee-related ~~expenses ($7 million)~~ and information systems ~~costs ($6 million).~~expenses resulting from expanded operations.

Interest expense, net of ~~$189~~$144 million for the first nine months of ~~2018~~2019 decreased ~~$22~~$45 million compared to the same prior year period primarily due to repayment in ~~September 2017~~October 2018 of the ~~$600~~$350 million aggregate principal amount of ~~5.875%~~6.875% Senior Notes due ~~2017.~~2018 ($18 million), repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($17 million) and higher capitalized interest ($10 million).

Gathering and processing costs of ~~$325~~$351 million for the first nine months of ~~2018~~2019 increased ~~$219~~$27 million compared to the same prior year period primarily due to increased operating costs and fees in the ~~adoption of ASU 2014-09~~Permian Basin ($~~147~~41 million) and ~~increased~~the Rocky Mountain area ($7 million), partially offset by decreased operating costs in the ~~Eagle Ford ($26 million), the Permian Basin~~United Kingdom ($25 million) ~~and~~due to the ~~United Kingdom ($21 million).~~sale of operations in the fourth quarter of 2018.

Exploration costs of ~~$115~~$103 million for the first nine months of ~~2018~~2019 decreased $7$12 million from ~~$122~~$115 million for the same prior year period primarily due to decreased geological and geophysical costs in ~~the United States.~~Trinidad.

Impairments of ~~$161~~$290 million for the first nine months of ~~2018~~2019 were ~~$165~~$129 million ~~lower~~higher than impairments for the same prior year period primarily due to ~~decreased~~increased impairments of proved properties and other assets in the United States ($~~129~~98 million) and ~~decreased~~increased amortization of unproved property costs in the United States ($3431 million), which was caused by ~~a decrease~~an increase in EOG's ~~estimates~~estimate of undeveloped properties not expected to be developed before lease expiration. ~~For the first nine months of 2017, proved property and other asset impairments in the United States were primarily related to the sale of legacy natural gas assets.~~ EOG recorded impairments of proved properties, other property, plant and equipment and other assets of ~~$34~~$132 million and ~~$165~~$34 million for the first nine months of ~~2018~~2019 and ~~2017,~~2018, respectively.

Taxes other than income for the first nine months of ~~2018~~2019 increased ~~$196~~$18 million to ~~$582~~$600 million ~~(6.5%~~(7.0% of wellhead revenues) from ~~$386~~$582 million ~~(7.0%~~(6.5% 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 ($171 million) and increased~~ ad valorem/property taxes in the United States ($1741 million) primarily as a result of increased valuation of the underlying assets and higher payroll taxes in Trinidad ($8 million), partially offset by decreases in severance/production taxes in the United States ($14 million) and Trinidad ($4 million) and an increase in credits available to EOG in the first nine months of 2019 for state incentive severance tax rate reductions ($12 million).

Other ~~expense~~income, net of $5$23 million for the first nine months of ~~2018~~2019 increased ~~$13~~$28 million compared to ~~other income of $8 million for~~ the same prior year period primarily due to an increase in interest income ($14 million), a decrease in deferred compensation expense ($7 million) and higher foreign currency exchange ~~losses.~~gains ($6 million).

EOG recognized an income tax provision of $616 million for the first nine months of 2019 compared to an income tax provision of $626 million for the ~~first nine months of 2018 compared to an income tax provision of $96 million for the~~ same period in ~~2017,~~2018, primarily due to ~~an increase in~~decreased pretax ~~income.~~income, partially offset by the absence of tax benefits from certain tax reform measurement-period adjustments. The net effective tax rate for the first nine months of ~~2018 decreased~~2019 increased to 23% from 20% ~~from 39% for the first nine months of 2017.~~in 2018. The ~~lower~~higher effective tax rate is ~~primarily~~mostly due to the reduction in the U.S. federal statutory tax rate to 21% in 2018 from 35% in 2017 and foreign income in the United Kingdom for which no taxes are recorded due to valuation allowances, partially offset by a reduction inabsence of tax benefits from ~~stock-based compensation.~~certain tax reform measurement-period adjustments.

Capital Resources and Liquidity

Cash Flow.The primary sources of cash for EOG during the nine months ended September 30, ~~2018~~2019, were funds generated from operations. The primary uses of cash were funds used in operations; exploration and development expenditures; long-term debt repayments; dividend payments to stockholders; and other property, plant and equipment ~~expenditures; and purchases of treasury stock in connection with stock compensation plans.~~expenditures. During the first nine months of ~~2018~~2019, EOG's cash balance increased ~~$440~~$27 million to ~~$1,274~~$1,583 million from ~~$834~~$1,556 million at December 31, ~~2017~~2018.

Net cash provided by operating activities of ~~$5,683~~$6,356 million for the first nine months of ~~2018~~2019 increased ~~$2,745~~$673 million compared to the same period of ~~2017~~2018 primarily due to ~~an increase~~a favorable change in ~~wellhead revenues~~working capital ($~~3,426 million) and favorable changes in gathering, processing and marketing revenues less marketing costs ($76~~474 million), ~~net cash paid for interest ($30 million) and~~a decrease in net cash paid for income taxes ($11396 million)~~, partially offset by increases~~ and an increase in cash ~~operating expenses ($556 million) and net cash paid~~received for settlements of commodity derivative contracts ($~~185~~320 million), partially offset by a decrease in wellhead revenues ($315 million) and an ~~unfavorable change~~increase in ~~working capital~~cash operating expenses ($~~132~~167 million).

Net cash used in investing activities of ~~$4,878~~$4,980 million for the first nine months of ~~2018~~2019 increased by ~~$2,123~~$102 million compared to the same period of ~~2017~~2018 due to an increase in additions to oil and gas properties ($~~1,644~~295 million), ~~an unfavorable~~partially offset by a favorable change in components of working capital associated with investing activities ($~~216~~134 million), an increase in proceeds from the sale of assets ($24 million), a decrease in ~~proceeds from the sales of assets~~other investing activities ($~~180~~20 million), and ~~an increase~~a decrease in additions to other property, plant and equipment ($6315 million).

Net cash used in financing activities of $1,348 million for the first nine months of 2019 included repayments of long-term debt ($900 million) and cash dividend payments ($421 million). Net cash used in financing activities of $363 million for the first nine months of 2018 included cash dividend payments ($311 million) and purchases of treasury stock in connection with stock compensation plans ($59 million), partially offset by proceeds from stock options exercised and employee stock purchase plan activity ($12 million). Net cash used in financing activities of $933 million for the first nine months of 2017 included repayments of long-term debt ($600 million), cash dividend payments ($289 million) and purchases of treasury stock in connection with stock compensation plans ($50 million).

Total Expenditures. For the year ~~2018,~~2019, EOG's budget for exploration and development and other property, plant and equipment expenditures is approximately ~~$5.8~~$6.2 billion to ~~$6.0~~$6.4 billion, excluding acquisitions and non-cash transactions. The table below sets out components of total expenditures for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017~~2018 (in millions):

Leasehold Acquisitions ⁽¹⁾

Property Acquisitions ⁽²⁾

Other Property, Plant and Equipment ⁽³⁾

Exploration and development expenditures of ~~$4,909~~$5,056 million for the first nine months of ~~2018~~2019 were ~~$1,643~~$147 million higher than the same period of ~~2017~~2018 primarily due to increased property acquisitions ($253 million) and increased exploration and drilling expenditures in ~~the United States~~Trinidad ($~~1,644 million), increased property acquisitions ($69 million) and increased facilities expenditures ($62~~28 million), partially offset by decreased ~~exploration and drilling expenditures in Trinidad ($96 million), decreased~~ leasehold acquisitions ($29130 million) and decreased ~~geological~~facilities expenditures ($19 million). Exploration and ~~geophysical~~development expenditures ~~($15 million).~~for the first nine months of 2019 of $5,056 million consisted of $4,341 million in development drilling and facilities, $355 million in exploration, $332 million in property acquisitions and $28 million in capitalized interest. Exploration and development expenditures for the first nine months of 2018 of $4,909 million consisted of $4,353 million in development drilling and facilities, $459 million in exploration, $79 million in property acquisitions and $18 million in capitalized interest. Exploration and development expenditures for the first nine months of 2017 of $3,266 million consisted of $2,734 million in development drilling and facilities, $501 million in exploration, $21 million in capitalized interest and $10 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 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,~~2018, filed on February ~~27, 2018,~~26, 2019, 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 September 30, ~~2018,~~2019, as a net ~~liability~~asset of ~~$126~~$123 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 October ~~26, 2018.~~29, 2019. 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 November 30, 2018 (closed) 15,000
$ 1.063
December 2018 15,000
1.063

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



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


2019
January 1, 2019 through November 30, 2019 (closed)	20,000	$	1.075
December 2019	20,000	1.075

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 October ~~26, 2018.~~29, 2019. 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 September 30, 2018 (closed) 37,000
$ 3.818
October 1, 2018 through November 30, 2018 (closed) 52,000
3.911
December 2018 52,000
3.911

2019
January 1, 2019 through December 31, 2019 13,000
$ 5.572



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


2019
January 1, 2019 through November 30, 2019 (closed)	13,000	$	5.572
December 2019	13,000	5.572

Presented below is a comprehensive summary of EOG's crude oil price swap contracts through October ~~26, 2018,~~29, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2019
April 2019 (closed)	25,000	$	60.00
May 1, 2019 through September 30, 2019 (closed)	150,000	62.50
October 1, 2019 through December 31, 2019	150,000	62.50

Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through October 29, 2019. The weighted average price differential expressed in dollars per million British thermal units ($/MMBtu) represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtu per day (MMBtud) covered by the basis swap contracts.



Rockies Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)


2020
January 1, 2020 through December 31, 2020	30,000	$	0.549

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October ~~26, 2018, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).~~

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 October 26, 2018,29, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

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, capital expenditures, 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, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital ~~costs,~~expenditures, generate ~~income or~~ cash flows, pay down or refinance 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:

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~~or 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.

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 4240 through 4543 of EOG's Annual Report on Form 10-K for the year ended December 31, ~~2017,~~2018, filed on February ~~27,~~26, 2019 (EOG's 2018 ~~(EOG's 2017~~ Annual Report); and (ii) Note 12, "Risk Management Activities," to EOG's Consolidated Financial Statements on pages ~~F-30~~F-29 through ~~F-33~~F-31 of EOG's ~~2017~~2018 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.

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.

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:

Price Paid Per Share

Announced Plans or Programs

of Shares that May Yet

Shares Purchased ⁽¹⁾

Price Paid Per Share

Announced Plans or Programs

of Shares that May Yet

Be Purchased Under The Plans or Programs ⁽²⁾

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.



Title of each class	Number of shares
Common Stock, par value $0.01 per share	~~579,903,041 (as~~581,764,095	(as of October ~~26, 2018)~~25, 2019)



PART I.	FINANCIAL INFORMATION		Page No.

	ITEM 1.	Financial Statements (Unaudited)

		Condensed Consolidated Statements of Income and Comprehensive Income - Three Months ~~Ended September 30, 2018 and 2017~~ and Nine Months Ended September 30, ~~2018~~2019 and ~~2017~~2018	3

		Condensed Consolidated Balance Sheets - September 30, ~~2018~~2019 and December 31, ~~2017~~2018	4

		Condensed Consolidated Statements of ~~Cash Flows~~Stockholders' Equity - Three Months and Nine Months Ended September 30, ~~2018~~2019 and ~~2017~~2018	5

		Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2019 and 2018	7

		Notes to Condensed Consolidated Financial Statements	68

	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2021

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	3736

	ITEM 4.	Controls and Procedures	3736

PART II.	OTHER INFORMATION

	ITEM 1.	Legal Proceedings	3837

	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3837

	ITEM 4.	Mine Safety Disclosures	3837

	ITEM 6.	Exhibits	3938

SIGNATURES			40


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017			2019			2018			2019			2018
Operating Revenues and Other
Crude Oil and Condensate	$	2,655,278		$	1,451,410		$	7,134,114		$	4,326,925		$	2,418,989		$	2,655,278		$	7,148,258		$	7,134,114
Natural Gas Liquids	353,704			180,038			861,473			480,389			164,736			353,704			569,748			861,473
Natural Gas	311,713			220,402			912,324			675,012			269,625			311,713			874,489			912,324
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	(52,081		)	(6,606		)	(297,735		)	64,860			85,902			(52,081		)	242,622			(297,735		)
Gathering, Processing and Marketing	1,360,992			784,368			3,899,250			2,289,702			1,334,450			1,360,992			4,121,490			3,899,250
Gains (Losses) on Asset Dispositions, Net	115,944			(8,202		)	94,658			(33,876		)	(523		)	115,944			3,650			94,658
Other, Net	36,074			23,434			96,779			64,869			30,276			36,074			99,470			96,779
Total	4,781,624			2,644,844			12,700,863			7,867,881			4,303,455			4,781,624			13,059,727			12,700,863
Operating Expenses
Lease and Well	321,568			251,943			936,236			762,906			348,883			321,568			1,032,455			936,236
Transportation Costs	196,027			183,565			550,781			548,635			199,365			196,027			549,988			550,781
Gathering and Processing Costs	114,063			32,590			324,577			105,480			127,549			114,063			351,487			324,577
Exploration Costs	32,823			30,796			115,137			122,401			34,540			32,823			103,386			115,137
Dry Hole Costs	358			50			5,260			77			24,138			358			28,001			5,260
Impairments	44,617			53,677			160,934			325,798			105,275			44,617			289,761			160,934
Marketing Costs	1,326,974			793,536			3,853,827			2,320,671			1,343,293			1,326,974			4,114,265			3,853,827
Depreciation, Depletion and Amortization	918,180			846,222			2,515,445			2,527,642			953,597			918,180			2,790,496			2,515,445
General and Administrative	111,284			111,717			310,065			317,462			135,758			111,284			364,210			310,065
Taxes Other Than Income	209,043			125,912			582,395			386,319			203,098			209,043			600,418			582,395
Total	3,274,937			2,430,008			9,354,657			7,417,391			3,475,496			3,274,937			10,224,467			9,354,657
Operating Income	1,506,687			214,836			3,346,206			450,490			827,959			1,506,687			2,835,260			3,346,206
Other Income (Expense), Net	3,308			226			(4,516		)	8,349			9,118			3,308			23,233			(4,516		)
Income Before Interest Expense and Income Taxes	1,509,995			215,062			3,341,690			458,839			837,077			1,509,995			2,858,493			3,341,690
Interest Expense, Net	63,632			69,082			189,032			211,010			39,620			63,632			144,434			189,032
Income Before Income Taxes	1,446,363			145,980			3,152,658			247,829			797,457			1,446,363			2,714,059			3,152,658
Income Tax Provision	255,411			45,439			626,386			95,718			182,335			255,411			615,670			626,386
Net Income	$	1,190,952		$	100,541		$	2,526,272		$	152,111		$	615,122		$	1,190,952		$	2,098,389		$	2,526,272
Net Income Per Share
Basic	$	2.06		$	0.17		$	4.38		$	0.26		$	1.06		$	2.06		$	3.63		$	4.38
Diluted	$	2.05		$	0.17		$	4.35		$	0.26		$	1.06		$	2.05		$	3.61		$	4.35
Dividends Declared per Common Share	$	0.2200		$	0.1675		$	0.5900		$	0.5025
Average Number of Common Shares
Basic	577,254			574,783			576,431			574,370			577,839			577,254			577,498			576,431
Diluted	581,559			578,736			580,442			578,453			581,271			581,559			581,190			580,442
Comprehensive Income
Net Income	$	1,190,952		$	100,541		$	2,526,272		$	152,111		$	615,122		$	1,190,952		$	2,098,389		$	2,526,272
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(1,952		)	355			(179		)	1,924			833			(1,952		)	(2,616		)	(179		)
Other, Net of Tax	6			(25		)	18			(74		)	6			6			18			18
Other Comprehensive Income (Loss)	(1,946		)	330			(161		)	1,850			839			(1,946		)	(2,598		)	(161		)
Comprehensive Income	$	1,189,006		$	100,871		$	2,526,111		$	153,961		$	615,961		$	1,189,006		$	2,095,791		$	2,526,111


	September 30, 2018			December 31, 2017			September 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,274,132		$	834,228		$	1,583,105		$	1,555,634
Accounts Receivable, Net	2,151,247			1,597,494			1,927,996			1,915,215
Inventories	766,964			483,865			778,120			859,359
Assets from Price Risk Management Activities	1,569			7,699			122,627			23,806
Income Taxes Receivable	320,938			113,357			135,680			427,909
Other	302,242			242,465			272,203			275,467
Total	4,817,092			3,279,108			4,819,731			5,057,390
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	56,799,237			52,555,741			61,620,033			57,330,016
Other Property, Plant and Equipment	4,191,958			3,960,759			4,394,486			4,220,665
Total Property, Plant and Equipment	60,991,195			56,516,500			66,014,519			61,550,681
Less: Accumulated Depreciation, Depletion and Amortization	(33,043,454		)	(30,851,463		)	(35,810,197		)	(33,475,162		)
Total Property, Plant and Equipment, Net	27,947,741			25,665,037			30,204,322			28,075,519
Deferred Income Taxes	16,880			17,506			1,998			777
Other Assets	856,023			871,427			1,516,218			800,788
Total Assets	$	33,637,736		$	29,833,078		$	36,542,269		$	33,934,474
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,435,773		$	1,847,131		$	2,395,080		$	2,239,850
Accrued Taxes Payable	249,234			148,874			302,774			214,726
Dividends Payable	126,829			96,410			166,215			126,971
Liabilities from Price Risk Management Activities	132,618			50,429
Current Portion of Long-Term Debt	1,262,874			356,235			1,014,200			913,093
Current Portion of Operating Lease Liabilities							384,348			—
Other	217,819			226,463			211,096			233,724
Total	4,425,147			2,725,542			4,473,713			3,728,364

Long-Term Debt	5,171,949			6,030,836			4,163,115			5,170,169
Other Liabilities	1,302,249			1,275,213			1,858,357			1,258,355
Deferred Income Taxes	4,199,921			3,518,214			4,922,804			4,413,398
Commitments and Contingencies (Note 8)

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 580,308,937 Shares Issued at September 30, 2018 and 578,827,768 Shares Issued at December 31, 2017	205,803			205,788
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,066,483 Shares Issued at September 30, 2019 and 580,408,117 Shares Issued at December 31, 2018							205,821			205,804
Additional Paid in Capital	5,626,259			5,536,547			5,769,073			5,658,794
Accumulated Other Comprehensive Loss	(19,458		)	(19,297		)	(3,689		)	(1,358		)
Retained Earnings	12,778,104			10,593,533			15,179,381			13,543,130
Common Stock Held in Treasury, 478,042 Shares at September 30, 2018 and 350,961 Shares at December 31, 2017	(52,238		)	(33,298		)
Common Stock Held in Treasury, 289,903 Shares at September 30, 2019 and 385,042 Shares at December 31, 2018							(26,306		)	(42,182		)
Total Stockholders' Equity	18,538,470			16,283,273			21,124,280			19,364,188
Total Liabilities and Stockholders' Equity	$	33,637,736		$	29,833,078		$	36,542,269		$	33,934,474


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2019			2018
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	2,526,272		$	152,111		$	2,098,389		$	2,526,272
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	2,515,445			2,527,642			2,790,496			2,515,445
Impairments	160,934			325,798			289,761			160,934
Stock-Based Compensation Expenses	116,290			101,537			132,323			116,290
Deferred Income Taxes	681,702			114,850			508,576			681,702
(Gains) Losses on Asset Dispositions, Net	(94,658		)	33,876
Gains on Asset Dispositions, Net							(3,650		)	(94,658		)
Other, Net	15,314			(4,514		)	4,155			15,314
Dry Hole Costs	5,260			77			28,001			5,260
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	297,735			(64,860		)	(242,622		)	297,735
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	(180,228		)	4,730			139,708			(180,228		)
Other, Net	1,652			270			1,215			1,652
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(553,529		)	(25,445		)	(5,855		)	(553,529		)
Inventories	(286,817		)	(17,674		)	55,598			(286,817		)
Accounts Payable	537,525			112,894			134,253			537,525
Accrued Taxes Payable	(36,891		)	(49,967		)	88,047			(36,891		)
Other Assets	(103,334		)	(83,940		)	394,573			(103,334		)
Other Liabilities	(14,776		)	(69,224		)	(18,315		)	(14,776		)
Changes in Components of Working Capital Associated with Investing and Financing Activities	95,484			(120,373		)	(38,677		)	95,484
Net Cash Provided by Operating Activities	5,683,380			2,937,788			6,355,976			5,683,380
Investing Cash Flows
Additions to Oil and Gas Properties	(4,571,932		)	(2,927,988		)	(4,866,882		)	(4,571,932		)
Additions to Other Property, Plant and Equipment	(202,384		)	(139,558		)	(187,350		)	(202,384		)
Proceeds from Sales of Assets	11,582			191,593			35,409			11,582
Other Investing Activities	(19,993		)	—			—			(19,993		)
Changes in Components of Working Capital Associated with Investing Activities	(95,541		)	120,469			38,677			(95,541		)
Net Cash Used in Investing Activities	(4,878,268		)	(2,755,484		)	(4,980,146		)	(4,878,268		)
Financing Cash Flows
Long-Term Debt Repayments	—			(600,000		)	(900,000		)	—
Dividends Paid	(311,075		)	(289,261		)	(420,851		)	(311,075		)
Treasury Stock Purchased	(58,558		)	(50,374		)	(22,238		)	(58,558		)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	12,098			11,174			9,558			12,098
Repayment of Capital Lease Obligation	(5,052		)	(4,897		)
Debt Issuance Costs							(5,016		)	—
Repayment of Finance Lease Liabilities							(9,638		)	(5,052		)
Changes in Components of Working Capital Associated with Financing Activities	57			(96		)	—			57
Net Cash Used in Financing Activities	(362,530		)	(933,454		)	(1,348,185		)	(362,530		)
Effect of Exchange Rate Changes on Cash	(2,678		)	(2,607		)	(174		)	(2,678		)
Increase (Decrease) in Cash and Cash Equivalents	439,904			(753,757		)
Increase in Cash and Cash Equivalents							27,471			439,904
Cash and Cash Equivalents at Beginning of Period	834,228			1,599,895			1,555,634			834,228
Cash and Cash Equivalents at End of Period	$	1,274,132		$	846,138		$	1,583,105		$	1,274,132



Delaware		47-0684736
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



	Three Months Ended September 30, 2018						Nine Months Ended September 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	$	2,655,278	$	2,655,278	$	—	$	7,134,114	$	7,134,114	$	—
Natural Gas Liquids	353,704		352,084		1,620		861,473		856,628		4,845
Natural Gas	311,713		256,169		55,544		912,324		770,441		141,883
Gathering, Processing and Marketing	1,360,992		1,355,909		5,083		3,899,250		3,883,222		16,028
Total Operating Revenues and Other	4,781,624		4,719,377		62,247		12,700,863		12,538,107		162,756
Operating Expenses
Gathering and Processing Costs	114,063		56,899		57,164		324,577		177,849		146,728
Marketing Costs	1,326,974		1,321,891		5,083		3,853,827		3,837,799		16,028
Total Operating Expenses	3,274,937		3,212,690		62,247		9,354,657		9,191,901		162,756
Operating Income	1,506,687		1,506,687		—		3,346,206		3,346,206		—


	Nine Months Ended September 30, 2018				Nine Months Ended September 30, 2017				Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
	Number of Stock Options/SARs		Weighted Average Grant Price		Number of Stock Options/SARs		Weighted Average Grant Price		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	8,310		$	96.90	9,103		$	83.89
Granted	1,884		126.65		2,260		96.24		1,946		75.43		1,884		126.65
Exercised ⁽¹⁾	(2,144	)	69.62		(1,674	)	55.63		(586	)	61.19		(2,144	)	69.62
Forfeited	(167	)	91.89		(269	)	90.22		(200	)	104.89		(167	)	91.89
Outstanding at September 30 ⁽²⁾	8,676		$	96.55	10,167		$	83.02	9,470		$	94.53	8,676		$	96.55
Vested or Expected to Vest ⁽³⁾	8,316		$	96.08	9,799		$	82.69	9,127		$	94.51	8,316		$	96.08
Exercisable at September 30 ⁽⁴⁾	4,202		$	85.80	5,517		$	75.59	5,307		$	94.08	4,202		$	85.80


(1)	The total intrinsic value of stock options/SARs exercised ~~for~~during the nine months ended September 30, 2019 and 2018 ~~and 2017~~ was ~~$103.7~~$13.3 million and ~~$66.6~~$103.7 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.


(1)	The total intrinsic value of restricted stock and restricted stock units released ~~for~~during the nine months ended September 30, 2019 and 2018 ~~and 2017~~ was ~~$80.2~~$61.2 million and ~~$81.6~~$80.2 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.


(1)	Upon completion of the Performance Period for the ~~Performance Awards~~performance units granted in ~~2014~~2015 and ~~2013,~~2014, a performance multiple of 200% was applied to each of the grants resulting in additional grants of ~~Performance Awards~~performance units in February ~~2018~~2019 and February ~~2017,~~2018, respectively.


(4)	Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of ~~143,610~~102 thousand and a maximum of ~~921,940 Performance Awards~~1,094 thousand performance units could be outstanding.


(1)	Net of capitalized interest of ~~$18~~$28 million and ~~$21~~$18 million for the nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, respectively.


(1)	Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.


	At September 30, 2018		At December 31, 2017		At September 30, 2019		At December 31, 2018
Total Assets
United States	$	32,656,676	$	28,312,599	$	35,765,137	$	33,178,733
Trinidad	619,127		974,477		617,465		629,633
Other International ⁽¹⁾	361,933		546,002		159,667		126,108
Total	$	33,637,736	$	29,833,078	$	36,542,269	$	33,934,474




FORM	10-Q



	Nine Months Ended September 30, 2018
Balance at January 1	$	2,167
Additions Pending the Determination of Proved Reserves	6,497
Reclassifications to Proved Properties	(5,346		)
Costs Charged to Expense	(433		)
Balance at September 30	$	2,885



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 October 31, 2018 (closed)	120,000	$	3.38	96,000	$	2.94
November 2018	120,000	3.38		96,000	2.94


(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. The United Kingdom operations were sold in the fourth quarter of 2018.


(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).


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


(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 $0.43 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 as a deduction to Natural Gas revenues.


(1)	Leasehold acquisitions included ~~$162~~$64 million and ~~$214~~$162 million for the nine-month periods ended September 30, ~~2018~~2019 and ~~2017,~~2018, respectively, related to non-cash property exchanges.


(2)	Property acquisitions included $21 million and $60 million for the nine-month ~~period~~periods ended September 30, 2019 and 2018, respectively, related to non-cash property exchanges.


(3)	Other property, plant and equipment included $49 million of non-cash additions for the nine-month period ended September 30, 2018 ~~primarily related to~~made in connection with a ~~capital~~finance lease transaction in the Permian Basin.



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

July 1, 2018 - July 31, 2018	14,941	$	126.48	—	6,386,200
August 1, 2018 - August 31, 2018	46,082	122.64		—	6,386,200
September 1, 2018 - September 30, 2018	157,146	120.37		—	6,386,200
Total	218,169	121.27		—


(2)	In September 2001, the Board authorized the repurchase of up to 10 million shares of EOG's common stock. During the third quarter of ~~2018,~~2019, EOG did not repurchase any shares under the Board-authorized repurchase program.



Exhibit No.		Description

~~10.1~~3.1(a)	-	Restated Certificate of Incorporation, dated September 3, 1987 (incorporated by reference to Exhibit 3.1(a) to EOG's Annual Report on Form ~~of Restricted Stock Award Agreement~~10-K for ~~Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to annual grants made effective September 27, 2018 and subsequent grants)~~the year ended December 31, 2008) (SEC File No. 001-09743).

~~10.2~~3.1(b)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 5, 1993 (incorporated by reference to Exhibit 4.1(b) to EOG's Registration Statement on Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to annual grants made effective September 27, 2018 and subsequent grants)S-8, SEC File No. 33-52201, filed February 8, 1994).

~~10.3~~3.1(c)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated June 14, 1994 (incorporated by reference to Exhibit 4.1(c) to EOG's Registration Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995).

3.1(d)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (incorporated by reference to Exhibit 3(d) to EOG's Registration Statement on Form S-3, SEC File No. 333-09919, filed August 9, 1996).

3.1(e)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (incorporated by reference to Exhibit 3(e) to EOG's Registration Statement on Form S-3, SEC File No. 333-44785, filed January 23, 1998).

3.1(f)	-	Certificate of Ownership and Merger Merging EOG Resources, Inc. into Enron Oil & Gas Company, dated August 26, 1999 (incorporated by reference to Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999) (SEC File No. 001-09743).

3.1(g)	-	Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (incorporated by reference to Exhibit 2 to EOG's Registration Statement on Form 8-A, SEC File No. 001-09743, filed February 18, 2000).

3.1(h)	-	Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 13, 2000 (incorporated by reference to Exhibit 3.1(j) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).

3.1(i)	-	Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 13, 2000 (incorporated by reference to Exhibit 3.1(k) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).

3.1(j)	-	Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (incorporated by reference to Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 2004) (SEC File No. 001-09743).

3.1(k)	-	Amended Certificate of Designations of Series E Junior Participating Preferred Stock, dated March 7, 2005 (incorporated by reference to Exhibit 3.1(m) to EOG's Annual Report on Form 10-K for the year ended December 31, 2007) (SEC File No. 001-09743).

3.1(l)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005 (incorporated by reference to Exhibit 3.1(l) to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005) (SEC File No. 001-09743).

3.1(m)	-	Certificate of Elimination of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated March 6, 2008 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed March 6, 2008) (SEC File No. 001-09743).

3.1(n)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated April 28, 2017 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed May 2, 2017) (SEC File No. 001-09743).

3.2	-	Bylaws, dated August 23, 1989, as amended and restated effective as of September 22, 2015 (incorporated by reference to Exhibit 3.1 to EOG's Current Report on Form 8-K, filed September 28, 2015) (SEC File No. 001-09743).

10.1	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to ~~annual~~ grants made effective September ~~27, 2018~~26, 2019 and subsequent grants).

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.



Exhibit No.		Description

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

95	-	Mine Safety Disclosure Exhibit.

*101.INS	-	Inline XBRL Instance ~~Document.~~Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

*101.SCH	-	Inline XBRL Schema Document.

*101.CAL	-	Inline XBRL Calculation Linkbase Document.

*101.DEF	-	Inline XBRL Definition Linkbase Document.

*101.LAB	-	Inline XBRL Label Linkbase Document.

*101.PRE	-	Inline XBRL Presentation Linkbase Document.

104	-	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).



			EOG RESOURCES, INC.
			(Registrant)



Date:	November ~~1, 2018~~6, 2019	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)