Current Report Filing (8-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 27, 2018

_______________

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation)	1-9743 (Commission File Number)	47-0684736 (I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

713-651-7000

(Registrant's telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

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

EOG RESOURCES, INC.

Item 2.02 Results of Operations and Financial Condition.

On February 27, 2018, EOG Resources, Inc. issued a press release announcing fourth quarter and full year 2017 financial and operational results and first quarter and full year 2018 forecast and benchmark commodity pricing information (see Item 7.01 below). A copy of this release is attached as Exhibit 99.1 to this filing and is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 7.01 Regulation FD Disclosure.

Accompanying the press release announcing fourth quarter and full year 2017 financial and operational results attached hereto as Exhibit 99.1 is first quarter and full year 2018 forecast and benchmark commodity pricing information for EOG Resources, Inc., which information is incorporated herein by reference. This information shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

99.1 Press Release of EOG Resources, Inc. dated February 27, 2018 (including the accompanying first quarter and full year 2018 forecast and benchmark commodity pricing information).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



		EOG RESOURCES, INC. (Registrant)



Date: February 27, 2018	By:	/s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

EXHIBIT 99.1



EOG Resources, Inc.	P.O. Box 4362, Houston, TX 77210-4362
News Release
For Further Information Contact:	Investors
	David J. Streit
	(713) 571-4902
	Neel Panchal
	(713) 571-4884
	W. John Wagner
	(713) 571-4404

	Media and Investors
	Kimberly M. Ehmer
	(713) 571-4676

EOG Resources Reports Fourth Quarter and Full Year 2017 Results and Announces 2018 Capital Program


•	Delivers 20 Percent U.S. Crude Oil Production Growth and Pays Dividend within Cash Flow


•	Lowers Per-Unit Transportation and DD&A Expenses Below Targets


•	Increases Proved Reserves 18 Percent and Replaces 201 Percent of 2017 Production at Low Finding Costs


•	Raises Common Stock Dividend 10 Percent


•	Targets 18 Percent Crude Oil Production Growth and 16 Percent Total Production Growth for 2018 with Significant Free Cash Flow at $60 Oil


•	Expects to Earn Double-Digit ROCE in 2018

FOR IMMEDIATE RELEASE: Tuesday, February 27, 2018

HOUSTON - EOG Resources, Inc. (EOG) today reported fourth quarter 2017 net income of $2,430 million, or $4.20 per share. This compares to a fourth quarter 2016 net loss of $142 million, or $0.25 per share. For the full year 2017, EOG reported net income of $2,583 million, or $4.46 per share, compared to a net loss of $1,097 million, or $1.98 per share, for the full year 2016.

Adjusted non-GAAP net income for the fourth quarter 2017 was $401 million, or $0.69 per share, compared to an adjusted non-GAAP net loss of $7 million, or $0.01 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2017 was $648 million, or $1.12 per share, compared to an adjusted non-GAAP net loss of $893 million, or $1.61 per share, for the full year 2016. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. One of the adjusting items in the fourth quarter and full year 2017 was a non-cash reduction in income tax expense of $2.2 billion, or $3.75 per share, related to the revaluation of EOG’s deferred tax liability and certain other items resulting from the Tax Cuts and Jobs Act. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Higher commodity prices, increased production volumes, well productivity improvements and per-unit cost reductions resulted in significant increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2017 compared to the fourth quarter 2016. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights

Crude oil and condensate volumes in the U.S. increased 20 percent in 2017 to 335,000 barrels of oil per day (Bopd). Increased development activity and well productivity improvements supported the volume increase. Total company natural gas liquids (NGLs) volumes grew 8 percent while natural gas volumes decreased 6 percent primarily due to the sale of the company’s Barnett and Haynesville Shale dry gas assets in late 2016. Transportation expenses decreased 11 percent and depreciation, depletion and amortization expenses decreased 12 percent, on a per-unit basis.

Increased development activity drove substantial volume increases in the Eagle Ford and Delaware Basin during the fourth quarter. Total company crude oil and condensate volumes increased 40,200 Bopd compared to the third quarter 2017. Natural gas liquids volumes grew 15 percent while natural gas volumes increased 6 percent, compared to the third quarter 2017.

“EOG emerged from the industry downturn in 2017 with unprecedented levels of efficiency and productivity, driving oil production volumes to record levels with capital expenditures approximately one half the prior peak,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “EOG’s integrated teams demonstrated superb operational performance, overcoming a major hurricane and other challenges to deliver record production volumes and cost savings which surpassed original targets set at the beginning of the year.”

2018 Capital Plan

EOG’s disciplined capital plan is designed to achieve strong returns on capital employed and healthy growth while spending within cash flow. The company expects to grow total company crude oil volumes by 18 percent, generate double-digit ROCE and cover capital investment and dividend payments within discretionary cash flow. EOG can deliver on its 2018 plan at oil prices below $50 and generates significant free cash flow at a $60 oil price.

EOG’s return-based culture continues to drive cost reductions. The company targets lower well costs and per-unit operating expenses in 2018 despite a potentially inflationary operating environment. EOG is also focused on driving continued improvements in well productivity and pursuing exploration efforts in new plays.

Capital expenditures for 2018 are expected to range from $5.4 to $5.8 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions. EOG expects to complete approximately 690 net wells in 2018, compared to 536 net wells in 2017. Capital will be allocated primarily to EOG’s highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and the Bakken.

At least 90 percent of the wells completed in 2018 are expected to be premium. EOG has an inventory of approximately 8,000 such wells, which have a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices and $2.50 flat natural gas prices.

“EOG enters 2018 better positioned than ever to generate significant shareholder value through the development of its large and diverse inventory of high rate-of-return premium wells,” Thomas said. “We are determined to maintain the discipline, record-level operational efficiency and performance gained through the downturn. Our deep inventory of premium wells across the U.S. offers flexibility to adjust to changing conditions. We also see significant opportunities to increase our premium well inventory through organic exploration and development technology to further extend EOG’s return on capital advantage.”

Dividend Increase

The board of directors increased the cash dividend on the common stock by 10.4 percent. Effective with the dividend payable April 30, 2018, to stockholders of record as of April 16, 2018, the board declared a quarterly dividend of $0.185 per share on the common stock. The indicated annual rate is $0.74 per share.

Delaware Basin

2017 was a watershed year for EOG in the Delaware Basin, where it successfully integrated the Yates acquisition, identified 1,240 additional net premium well locations, added the First Bone Spring as its fourth premium play and reduced completed well costs by $800,000 per well. Delaware Basin crude oil and condensate volumes increased over 80 percent in 2017 and exceeded 100,000 Bopd in the fourth quarter 2017.

EOG continued active development of its 416,000 net acre position in the Delaware Basin in the fourth quarter 2017, completing 65 wells.

In the Delaware Basin Wolfcamp, in Lea County, NM, EOG completed a four-well package, the Calm Breeze 2 Fed Com #701-704H, with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,605 Bopd, 440 barrels per day (Bpd) of NGLs and 3.7 million cubic feet per day (MMcfd) of natural gas.

In the Delaware Basin First Bone Spring, in Lea County, NM, EOG completed the Righteous 6 State Com #301H with a treated lateral length of 7,100 feet and 30-day initial production rate of 1,305 Bopd, 170 Bpd of NGLs and 1.4 MMcfd of natural gas.

In the Delaware Basin Leonard, in Loving County, TX, EOG completed a four-well package, the State Atlas A#3H - D#6H, with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 1,215 Bopd, 270 Bpd of NGLs and 2.3 MMcfd of natural gas.

South Texas Eagle Ford and Austin Chalk

EOG continues to enhance the productivity of its bellwether asset in the South Texas Eagle Ford. Eight years after initiating development, EOG further reduced well costs and improved well performance during 2017 in its 520,000 net acre position in the crude oil window of this world class play. EOG also expanded its enhanced oil recovery program, adding 56 wells last year. For the full year 2017, crude oil production in the Eagle Ford and Austin Chalk increased one percent year-over-year despite interruption to producing volumes as a result of Hurricane Harvey.

In the fourth quarter, EOG completed 74 wells in the Eagle Ford. These included 13 wells with lateral lengths of more than 10,000 feet. In LaSalle County, EOG completed a four-well package, the White 5H-8H, with an average treated lateral length of 12,900 feet per well and average 30-day initial production rates per well of 1,545 Bopd, 80 Bpd of NGLs and 0.5 MMcfd of natural gas. In DeWitt County, EOG completed a four-well package, the Hendrix 8H-10H and the Hendrix 12H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 2,545 Bopd, 420 Bpd of NGLs and 2.4 MMcfd of natural gas.

EOG continued to test its position in the South Texas Austin Chalk, a geologically complex formation which lies above the South Texas Eagle Ford, completing four net wells in the fourth quarter.

Rockies

EOG’s Wyoming Powder River Basin and DJ Basin activity both contributed to the company’s 2017 crude oil production growth. In the Powder River Basin, EOG continued exploration activity on its 400,000 net acre position in the core of the play. The company tested the prospectivity of multiple target zones and also tested the aerial extent of various targets in the Powder River Basin during the year. In the DJ Basin, EOG achieved significant well cost reductions during 2017 through a focus on efficiency improvements in drilling and completion operations.

In the fourth quarter, EOG completed nine wells in the Powder River Basin. In Converse County, EOG completed the Mary’s Draw 453-0310H and 455-0310H wells with an average treated lateral length of 7,300 feet per well and average 30-day initial production rates per well of 1,280 Bopd, 610 Bpd of

NGLs and 7.6 MMcfd of natural gas. In the DJ Basin, EOG completed three wells in the fourth quarter. This included the Big Sandy 522-2536H with a treated lateral length of 8,800 feet and 30-day initial production rate of 1,100 Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.

Reserves

At year-end 2017, total company net proved reserves were 2,527 million barrels of oil equivalent (MMBoe), an increase of 18 percent compared to year-end 2016. Net proved reserve additions from all sources, excluding revisions due to price, replaced 201 percent of EOG’s 2017 production at a finding and development cost of $8.71 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 154 MMBoe and asset divestitures decreased net proved reserves by 21 MMBoe. (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)

For the 30^th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.

Hedging Activity

During the fourth quarter ended December 31, 2017, EOG entered into crude oil financial price swap contracts and differential basis swap contracts. A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.

Capital Structure and Asset Sales

At December 31, 2017, EOG’s total debt outstanding was $6.4 billion with a debt-to-total capitalization ratio of 28 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $5.6 billion with a net debt-to-total capitalization ratio of 25 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales for the full year 2017 totaled $227 million.

Conference Call February 28, 2018

EOG’s fourth quarter and full year 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, February 28, 2018. To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.

EOG Resources, Inc. 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 Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG’s actual results may differ materially from the measure and estimates presented or referenced herein. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:


•	the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;


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


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


•	the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;


•	the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;


•	the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;

•

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and

regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;


•	EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;


•	the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;


•	competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;


•	the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;


•	the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;


•	weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;


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


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


•	the extent to which EOG is successful in its completion of planned asset dispositions;


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


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


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


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


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


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


•	physical, electronic and cyber security breaches; and


•	the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

###



EOG RESOURCES, INC. Financial Report (Unaudited; in millions, except per share data)

	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2017		2016			2017		2016

Net Operating Revenues and Other	$	3,340.4	$	2,402.0		$	11,208.3	$	7,650.6
Net Income (Loss)	$	2,430.5	$	(142.4	)	$	2,582.6	$	(1,096.7	)
Net Income (Loss) Per Share
Basic	$	4.22	$	(0.25	)	$	4.49	$	(1.98	)
Diluted	$	4.20	$	(0.25	)	$	4.46	$	(1.98	)
Average Number of Common Shares
Basic		575.4		567.3			574.6		553.4
Diluted		579.2		567.3			578.7		553.4



Summary Income Statements (Unaudited; in thousands, except per share data)

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2017			2016			2017			2016
Net Operating Revenues and Other
Crude Oil and Condensate	$	1,929,471		$	1,366,223		$	6,256,396		$	4,317,341
Natural Gas Liquids		249,172			137,849			729,561			437,250
Natural Gas		246,922			215,373			921,934			742,152
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		(45,032	)		(65,787	)		19,828			(99,608	)
Gathering, Processing and Marketing		1,008,385			614,594			3,298,087			1,966,259
Gains (Losses) on Asset Dispositions, Net		(65,220	)		104,034			(99,096	)		205,835
Other, Net		16,741			29,753			81,610			81,403
Total		3,340,439			2,402,039			11,208,320			7,650,632
Operating Expenses
Lease and Well		281,941			241,846			1,044,847			927,452
Transportation Costs		191,717			193,319			740,352			764,106
Gathering and Processing Costs		43,295			32,516			148,775			122,901
Exploration Costs		22,941			39,110			145,342			124,953
Dry Hole Costs		4,532			193			4,609			10,657
Impairments		153,442			297,946			479,240			620,267
Marketing Costs		1,009,566			634,248			3,330,237			2,007,635
Depreciation, Depletion and Amortization		881,745			862,524			3,409,387			3,553,417
General and Administrative		117,005			102,182			434,467			394,815
Taxes Other Than Income		158,343			103,642			544,662			349,710
Total		2,864,527			2,507,526			10,281,918			8,875,913

Operating Income (Loss)		475,912			(105,487	)		926,402			(1,225,281	)

Other Income (Expense), Net		803			(17,198	)		9,152			(50,543	)

Income (Loss) Before Interest Expense and Income Taxes		476,715			(122,685	)		935,554			(1,275,824	)

Interest Expense, Net		63,362			71,325			274,372			281,681

Income (Loss) Before Income Taxes		413,353			(194,010	)		661,182			(1,557,505	)

Income Tax (Benefit)		(2,017,115	)		(51,658	)		(1,921,397	)		(460,819	)

Net Income (Loss)	$	2,430,468		$	(142,352	)	$	2,582,579		$	(1,096,686	)

Dividends Declared per Common Share	$	0.1675		$	0.1675		$	0.6700		$	0.6700



EOG RESOURCES, INC. Operating Highlights (Unaudited)

	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2017		2016		2017		2016
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) ^(A)
United States		366.9		306.0		335.0		278.3
Trinidad		1.1		0.9		0.9		0.8
Other International ^(B)		0.1		4.8		0.8		3.4
Total		368.1		311.7		336.7		282.5

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$	56.95	$	47.93	$	50.91	$	41.84
Trinidad		46.56		40.04		42.30		33.76
Other International ^(B)		45.72		38.96		57.20		36.72
Composite		56.97		47.76		50.91		41.76

Natural Gas Liquids Volumes (MBbld) ^(A)
United States		100.6		80.9		88.4		81.6
Other International ^(B)		—		—		—		—
Total		100.6		80.9		88.4		81.6

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$	26.92	$	18.51	$	22.61	$	14.63
Other International ^(B)		—		—		—		—
Composite		26.92		18.51		22.61		14.63

Natural Gas Volumes (MMcfd) ^(A)
United States		829		800		765		810
Trinidad		299		323		313		340
Other International ^(B)		32		22		25		25
Total		1,160		1,145		1,103		1,175

Average Natural Gas Prices ($/Mcf) ^(C)
United States	$	2.17	$	2.05	$	2.20	$	1.60
Trinidad		2.52		1.89		2.38		1.88
Other International ^(B)		4.23		3.85		3.89		3.64
Composite		2.31		2.04		2.29		1.73

Crude Oil Equivalent Volumes (MBoed) ^(D)
United States		605.6		520.3		551.0		494.9
Trinidad		51.0		54.6		53.0		57.5
Other International ^(B)		5.4		8.6		4.9		7.6
Total		662.0		583.5		608.9		560.0

Total MMBoe ^(D)		60.9		53.7		222.3		205.0


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


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


(C)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.

(D)

Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.



EOG RESOURCES, INC. Summary Balance Sheets (Unaudited; in thousands, except share data)

	December 31,			December 31,
	2017			2016
ASSETS
Current Assets
Cash and Cash Equivalents	$	834,228		$	1,599,895
Accounts Receivable, Net		1,597,494			1,216,320
Inventories		483,865			350,017
Assets from Price Risk Management Activities		7,699			—
Income Taxes Receivable		113,357			12,305
Other		242,465			206,679
Total		3,279,108			3,385,216

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		52,555,741			49,592,091
Other Property, Plant and Equipment		3,960,759			4,008,564
Total Property, Plant and Equipment		56,516,500			53,600,655
Less: Accumulated Depreciation, Depletion and Amortization		(30,851,463	)		(27,893,577	)
Total Property, Plant and Equipment, Net		25,665,037			25,707,078
Deferred Income Taxes		17,506			16,140
Other Assets		871,427			190,767
Total Assets	$	29,833,078		$	29,299,201


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,847,131		$	1,511,826
Accrued Taxes Payable		148,874			118,411
Dividends Payable		96,410			96,120
Liabilities from Price Risk Management Activities		50,429			61,817
Current Portion of Long-Term Debt		356,235			6,579
Other		226,463			232,538
Total		2,725,542			2,027,291


Long-Term Debt		6,030,836			6,979,779
Other Liabilities		1,275,213			1,282,142
Deferred Income Taxes		3,518,214			5,028,408
Commitments and Contingencies

Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares and 640,000,000 Shares Authorized at December 31, 2017 and 2016, respectively, and 578,827,768 Shares and 576,950,272 Shares Issued at December 31, 2017 and 2016, respectively		205,788			205,770
Additional Paid in Capital		5,536,547			5,420,385
Accumulated Other Comprehensive Loss		(19,297	)		(19,010	)
Retained Earnings		10,593,533			8,398,118
Common Stock Held in Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017 and 2016, respectively		(33,298	)		(23,682	)
Total Stockholders' Equity		16,283,273			13,981,581
Total Liabilities and Stockholders' Equity	$	29,833,078		$	29,299,201



EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands)
	Twelve Months Ended
	December 31,
	2017			2016
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Income (Loss)	$	2,582,579		$	(1,096,686	)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,409,387			3,553,417
Impairments		479,240			620,267
Stock-Based Compensation Expenses		133,849			128,090
Deferred Income Taxes		(1,473,872	)		(515,206	)
(Gains) Losses on Asset Dispositions, Net		99,096			(205,835	)
Other, Net		6,546			61,690
Dry Hole Costs		4,609			10,657
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		(19,828	)		99,608
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		7,438			(22,219	)
Excess Tax Benefits from Stock-Based Compensation		—			(29,357	)
Other, Net		1,204			10,971
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(392,131	)		(232,799	)
Inventories		(174,548	)		170,694
Accounts Payable		324,192			(74,048	)
Accrued Taxes Payable		(63,937	)		92,782
Other Assets		(658,609	)		(40,636	)
Other Liabilities		(89,871	)		(16,225	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		89,992			(156,102	)
Net Cash Provided by Operating Activities		4,265,336			2,359,063

Investing Cash Flows
Additions to Oil and Gas Properties		(3,950,918	)		(2,489,756	)
Additions to Other Property, Plant and Equipment		(173,324	)		(93,039	)
Proceeds from Sales of Assets		226,768			1,119,215
Net Cash Received from Yates Transaction		—			54,534
Changes in Components of Working Capital Associated with Investing Activities		(89,935	)		156,102
Net Cash Used in Investing Activities		(3,987,409	)		(1,252,944	)

Financing Cash Flows
Net Commercial Paper Repayments		—			(259,718	)
Long-Term Debt Borrowings		—			991,097
Long-Term Debt Repayments		(600,000	)		(563,829	)
Dividends Paid		(386,531	)		(372,845	)
Excess Tax Benefits from Stock-Based Compensation		—			29,357
Treasury Stock Purchased		(63,408	)		(82,125	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		20,840			23,296
Debt Issuance Costs		—			(1,602	)
Repayment of Capital Lease Obligation		(6,555	)		(6,353	)
Other, Net		(57	)		—
Net Cash Used in Financing Activities		(1,035,711	)		(242,722	)

Effect of Exchange Rate Changes on Cash		(7,883	)		17,992

Increase (Decrease) in Cash and Cash Equivalents		(765,667	)		881,389
Cash and Cash Equivalents at Beginning of Period		1,599,895			718,506
Cash and Cash Equivalents at End of Period	$	834,228		$	1,599,895



EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) To Net Income (Loss) (GAAP) (Unaudited; in thousands, except per share data)


The following chart adjusts the three-month and twelve-month periods ended December 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017 and 2016, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back acquisition costs and state apportionment change related to the Yates transaction in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017, to add back joint interest billings deemed uncollectible in 2017, and to eliminate the impact of tax reform in 2017. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

		Three Months Ended											Three Months Ended
		December 31, 2017											December 31, 2016

		Before Tax		Income Tax Impact			After Tax			Diluted Earnings per Share			Before Tax			Income Tax Impact			After Tax			Diluted Earnings per Share
Reported Net Income (Loss) (GAAP)	$	413,353	$	2,017,115		$	2,430,468		$	4.20		$	(194,010	)	$	51,658		$	(142,352	)	$	(0.25	)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		45,032		(16,142	)		28,890			0.05			65,787			(23,583	)		42,204			0.07
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		2,708		(971	)		1,737			—			—			29			29			—
Add: Net (Gains) Losses on Asset Dispositions		65,220		(23,315	)		41,905			0.07			(104,034	)		36,856			(67,178	)		(0.12	)
Add: Impairments		100,304		(35,954	)		64,350			0.11			217,839			(76,728	)		141,111			0.25
Add: Voluntary Retirement Expense		—		—			—			—			—			(57	)		(57	)		—
Add: Acquisition - State Apportionment Change		—		—			—			—			—			16,424			16,424			0.03
Add: Acquisition Costs		—		—			—			—			2,173			955			3,128			0.01
Add: Joint Interest Billings Deemed Uncollectible		4,528		(1,623	)		2,905			0.01			—			—			—			—
Less: Tax Reform Impact		—		(2,169,376	)		(2,169,376	)		(3.75	)		—			—			—			—
Adjustments to Net Income (Loss)		217,792		(2,247,381	)		(2,029,589	)		(3.51	)		181,765			(46,104	)		135,661			0.24

Adjusted Net Income (Loss) (Non-GAAP)	$	631,145	$	(230,266	)	$	400,879		$	0.69		$	(12,245	)	$	5,554		$	(6,691	)	$	(0.01	)

Average Number of Common Shares (GAAP)
Basic										575,394												567,337
Diluted										579,203												567,337



		Twelve Months Ended										Twelve Months Ended
		December 31, 2017										December 31, 2016

		Before Tax		Income Tax Impact		After Tax			Diluted Earnings per Share			Before Tax		Income Tax Impact		After Tax		Diluted Earnings per Share
Reported Net Income (Loss) (GAAP)	$	661,182	$	1,921,397	$	2,582,579		$	4.46		$	(1,557,505)	$	460,819	$	(1,096,686)	$	(1.98	)
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		(19,828)		7,107		(12,721	)		(0.02	)		99,608		(35,640)		63,968		0.12
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		7,438		(2,666)		4,772			0.01			(22,219)		7,950		(14,269)		(0.03	)
Add: Net (Gains) Losses on Asset Dispositions		99,096		(35,270)		63,826			0.11			(205,835)		61,491		(144,344)		(0.26	)
Add: Impairments		261,452		(93,718)		167,734			0.29			320,617		(113,368)		207,249		0.37
Add: Trinidad Tax Settlement		—		—		—			—			—		43,000		43,000		0.08
Add: Voluntary Retirement Expense		—		—		—			—			42,054		(15,047)		27,007		0.05
Add: Acquisition - State Apportionment Change		—		—		—			—			—		16,424		16,424		0.03
Add: Acquisition Costs		—		—		—			—			5,100		(88)		5,012		0.01
Add: Legal Settlement - Early Lease Termination		10,202		(3,657)		6,545			0.01			—		—		—		—
Add: Joint Venture Transaction Costs		3,056		(1,095)		1,961			—			—		—		—		—
Add: Joint Interest Billings Deemed Uncollectible		4,528		(1,623)		2,905			0.01			—		—		—		—
Less: Tax Reform Impact		—		(2,169,376)		(2,169,376	)		(3.75	)		—		—		—		—
Adjustments to Net Income (Loss)		365,944		(2,300,298)		(1,934,354	)		(3.34	)		239,325		(35,278)		204,047		0.37

Adjusted Net Income (Loss) (Non-GAAP)	$	1,027,126	$	(378,901)	$	648,225		$	1.12		$	(1,318,180)	$	425,541	$	(892,639)	$	(1.61	)

Average Number of Common Shares (GAAP)
Basic									574,620									553,384
Diluted									578,693									553,384



EOG RESOURCES, INC. Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) To Net Cash Provided by Operating Activities (GAAP) (Unaudited; in thousands) Calculation of Free Cash Flow (Non-GAAP) (Unaudited; in thousands)

The following chart reconciles the three-month and twelve-month periods ended December 31, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Other Non-Current Taxes, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2017. EOG management uses this information for comparative purposes within the industry.

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2017			2016			2017			2016

Net Cash Provided by Operating Activities (GAAP)	$	1,327,548		$	804,745		$	4,265,336		$	2,359,063

Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		16,420			33,931			122,688			104,199
Excess Tax Benefits from Stock-Based Compensation		—			7,286			—			29,357
Other Non-Current Taxes (Non-Current Impact of the Tax Cut Jobs Act)		(513,404	)		—			(513,404	)		—
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		366,686			220,939			392,131			232,799
Inventories		156,874			(33,131	)		174,548			(170,694	)
Accounts Payable		(211,298	)		(127,165	)		(324,192	)		74,048
Accrued Taxes Payable		13,970			21,214			63,937			(92,782	)
Other Assets		574,669			28,110			658,609			40,636
Other Liabilities		20,647			53,024			89,871			16,225
Changes in Components of Working Capital Associated with Investing and Financing Activities		(210,365	)		36,342			(89,992	)		156,102

Discretionary Cash Flow (Non-GAAP)	$	1,541,747		$	1,045,295		$	4,839,532		$	2,748,953

Discretionary Cash Flow (Non-GAAP) - Percentage Increase		47	%					76	%

Discretionary Cash Flow (Non-GAAP)							$	4,839,532
Less:
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) ^(a)								(4,228,859	)
Dividends Paid (GAAP)								(386,531	)
Free Cash Flow (Non-GAAP)							$	224,142



(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the twelve months ended December 31, 2017:

Total Expenditures (GAAP)	$	4,612,746
Less:
Asset Retirement Costs		(55,592	)
Non-Cash Acquisition of Unproved Properties		(255,711	)
Acquisition Costs of Proved Properties		(72,584	)
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)	$	4,228,859



EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) (Non-GAAP) to Net Income (Loss) (GAAP) (Unaudited; in thousands)

The following chart adjusts the three-month and twelve-month periods ended December 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2017			2016			2017			2016

Net Income (Loss) (GAAP)	$	2,430,468		$	(142,352	)	$	2,582,579		$	(1,096,686	)

Adjustments:
Interest Expense, Net		63,362			71,325			274,372			281,681
Income Tax Provision (Benefit)		(2,017,115	)		(51,658	)		(1,921,397	)		(460,819	)
Depreciation, Depletion and Amortization		881,745			862,524			3,409,387			3,553,417
Exploration Costs		22,941			39,110			145,342			124,953
Dry Hole Costs		4,532			193			4,609			10,657
Impairments		153,442			297,946			479,240			620,267
EBITDAX (Non-GAAP)		1,539,375			1,077,088			4,974,132			3,033,470
Total (Gains) Losses on MTM Commodity Derivative Contracts		45,032			65,787			(19,828	)		99,608
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		2,708			—			7,438			(22,219	)
(Gains) Losses on Asset Dispositions, Net		65,220			(104,034	)		99,096			(205,835	)

Adjusted EBITDAX (Non-GAAP)	$	1,652,335		$	1,038,841		$	5,060,838		$	2,905,024

Adjusted EBITDAX (Non-GAAP) - Percentage Increase		59	%					74	%



EOG RESOURCES, INC. Quantitative Reconciliation of Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as Used in the Calculation of The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) (Unaudited; in millions, except ratio data)

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.

	At			At
	December 31,			December 31,
	2017			2016

Total Stockholders' Equity - (a)	$	16,283		$	13,982

Current and Long-Term Debt (GAAP) - (b)		6,387			6,986
Less: Cash		(834	)		(1,600	)
Net Debt (Non-GAAP) - (c)		5,553			5,386

Total Capitalization (GAAP) - (a) + (b)	$	22,670		$	20,968

Total Capitalization (Non-GAAP) - (a) + (c)	$	21,836		$	19,368

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		28	%		33	%

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		25	%		28	%



EOG RESOURCES, INC.
Reserves Supplemental Data
(Unaudited)

2017 NET PROVED RESERVES RECONCILIATION SUMMARY
	United States			Trinidad			Other International			Total
CRUDE OIL & CONDENSATE (MMBbl)
Beginning Reserves	1,168.5			0.8			8.3			1,177.6
Revisions	58.0			0.1			(0.2		)	57.9
Purchases in place	1.1			—			—			1.1
Extensions, discoveries and other additions	207.1			0.3			0.1			207.5
Sales in place	(8.4		)	—			—			(8.4		)
Production	(122.2		)	(0.3		)	(0.2		)	(122.7		)
Ending Reserves	1,304.1			0.9			8.0			1,313.0

NATURAL GAS LIQUIDS (MMBbl)
Beginning Reserves	416.4			—			—			416.4
Revisions	46.9			—			—			46.9
Purchases in place	0.4			—			—			0.4
Extensions, discoveries and other additions	75.0			—			—			75.0
Sales in place	(2.9		)	—			—			(2.9		)
Production	(32.3		)	—			—			(32.3		)
Ending Reserves	503.5			—			—			503.5

NATURAL GAS (Bcf)
Beginning Reserves	3,021.2			280.9			15.8			3,317.9
Revisions	602.8			(27.4		)	8.6			584.0
Purchases in place	4.8			—			—			4.8
Extensions, discoveries and other additions	619.3			174.2			35.9			829.4
Sales in place	(56.4		)	—			—			(56.4		)
Production	(293.2		)	(114.3		)	(9.1		)	(416.6		)
Ending Reserves	3,898.5			313.4			51.2			4,263.1

OIL EQUIVALENTS (MMBoe)
Beginning Reserves	2,088.4			47.7			10.9			2,147.0
Revisions	205.3			(4.5		)	1.2			202.0
Purchases in place	2.3			—			—			2.3
Extensions, discoveries and other additions	385.4			29.3			6.1			420.8
Sales in place	(20.7		)	—			—			(20.7		)
Production	(203.4		)	(19.4		)	(1.6		)	(224.4		)
Ending Reserves	2,457.3			53.1			16.6			2,527.0

Net Proved Developed Reserves (MMBoe)
At December 31, 2016	1,038.5			44.5			10.9			1,093.9
At December 31, 2017	1,300.7			50.8			12.8			1,364.3

2017 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
	United States			Trinidad			Other International			Total

Acquisition Cost of Unproved Properties	$	424.1		$	2.4		$	—		$	426.5
Exploration Costs	144.5			62.6			16.5			223.6
Development Costs	3,540.7			107.2			13.2			3,661.1
Total Drilling	4,109.3			172.2			29.7			4,311.2
Acquisition Cost of Proved Properties	72.6			—			—			72.6
Asset Retirement Costs	50.2			2.3			3.1			55.6
Total Exploration & Development Expenditures	4,232.1			174.5			32.8			4,439.4
Gathering, Processing and Other	173.0			0.1			0.2			173.3
Total Expenditures	4,405.1			174.6			33.0			4,612.7
Proceeds from Sales in Place	(226.6		)	—			—			(226.6		)
Net Expenditures	$	4,178.5		$	174.6		$	33.0		$	4,386.1

RESERVE REPLACEMENT COSTS ($ / Boe) *
All-in Total, Net of Revisions	$	6.58		$	6.94		$	4.07		$	6.56
All-in Total, Excluding Revisions Due to Price	$	8.88		$	6.94		$	4.07		$	8.71

RESERVE REPLACEMENT *
Drilling Only	190		%	151		%	381		%	188		%
All-in Total, Net of Revisions & Dispositions	281		%	128		%	456		%	269		%
All-in Total, Excluding Revisions Due to Price	206		%	128		%	456		%	201		%
All-in Total, Liquids	244		%	133		%	-50		%	244		%

* See attached reconciliation schedule for calculation methodology



EOG RESOURCES, INC. Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP) As Used in the Calculation of Reserve Replacement Costs ($ / BOE) To Total Costs Incurred in Exploration and Development Activities (GAAP) (Unaudited; in millions, except ratio information)

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including an “All-In” calculation, which reflects total exploration and development expenditures divided by total net proved reserve additions from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

For the Twelve Months Ended December 31, 2017
	United States			Trinidad			Other International			Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	4,232.1		$	174.5		$	32.8		$	4,439.4
Less: Asset Retirement Costs	(50.2		)	(2.3		)	(3.1		)	(55.6		)
Non-Cash Acquisition Costs of Unproved Properties	(255.7		)	—			—			(255.7		)
Non-Cash Acquisition Cost of Proved Properties	(26.2		)	—			—			(26.2		)
Total Exploration & Development Expenditures (Non-GAAP) (a)	$	3,900.0		$	172.2		$	29.7		$	4,101.9

Total Expenditures (GAAP)	$	4,405.1		$	174.6		$	33.0		$	4,612.7
Less: Asset Retirement Costs	(50.2		)	(2.3		)	(3.1		)	(55.6		)
Non-Cash Acquisition Costs of Unproved Properties	(255.7		)	—			—			(255.7		)
Non-Cash Acquisition Costs of Proved Properties	(26.2		)	—			—			(26.2		)
Total Cash Expenditures (Non-GAAP)	$	4,073.0		$	172.3		$	29.9		$	4,275.2

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions due to price (b)	154.0			—			—			154.0
Revisions other than price	51.3			(4.5		)	1.2			48.0
Purchases in place	2.3			—			—			2.3
Extensions, discoveries and other additions (c)	385.4			29.3			6.1			420.8
Total Proved Reserve Additions (d)	593.0			24.8			7.3			625.1
Sales in place	(20.7		)	—			—			(20.7		)
Net Proved Reserve Additions From All Sources (e)	572.3			24.8			7.3			604.4

Production (f)	203.4			19.4			1.6			224.4

RESERVE REPLACEMENT COSTS ($ / Boe)
All-in Total, Net of Revisions (a / d)	$	6.58		$	6.94		$	4.07		$	6.56
All-in Total, Excluding Revisions Due to Price (a / (d - b))	$	8.88		$	6.94		$	4.07		$	8.71

RESERVE REPLACEMENT
Drilling Only (c / f)	190		%	151		%	381		%	188		%
All-in Total, Net of Revisions & Dispositions (e / f)	281		%	128		%	456		%	269		%
All-in Total, Excluding Revisions Due to Price ((e - b) / f)	206		%	128		%	456		%	201		%

Net Proved Reserve Additions From All Sources - Liquids (MMBbl)
Revisions	104.9			0.1			(0.2		)	104.8
Purchases in place	1.5			—			—			1.5
Extensions, discoveries and other additions (g)	282.1			0.3			0.1			282.5
Total Proved Reserve Additions	388.5			0.4			(0.1		)	388.8
Sales in place	(11.3		)	—			—			(11.3		)
Net Proved Reserve Additions From All Sources (h)	377.2			0.4			(0.1		)	377.5

Production (i)	154.5			0.3			0.2			155.0

RESERVE REPLACEMENT - LIQUIDS
Drilling Only (g / i)	183		%	100		%	50		%	182		%
All-in Total, Net of Revisions & Dispositions (h / i)	244		%	133		%	-50		%	244		%



EOG RESOURCES, INC. Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP) As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) To Total Costs incurred in Exploration and Development Activities (GAAP) (Unaudited; in millions, except ratio data)

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.

For the Twelve Months Ended December 31, 2017

PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)	Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	4,439.4
Less: Asset Retirement Costs	(55.6		)
Acquisition Costs of Unproved Properties	(426.5		)
Acquisition Cost of Proved Properties	(72.6		)
Drillbit Exploration & Development Expenditures (Non-GAAP) (j)	$	3,884.7

Total Proved Reserves - Extensions, discoveries and other additions (MMBoe)	420.8
Add: Conversion of proved undeveloped reserves to proved developed	152.6
Less: Proved undeveloped extensions and discoveries	(237.4		)
Proved Developed Reserves - Extensions and discoveries (MMBoe)	336.0

Total Proved Reserves - Revisions (MMBoe)	202.0
Less: Proved Undeveloped Reserves - Revisions	(33.1		)
Proved Developed - Revisions due to price	(143.0		)
Proved Developed Reserves - Revisions other than price (MMBoe)	25.9

Proved Developed Reserves - Extensions and discoveries plus revisions other than price (MMBoe) (k)	361.9

Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k)	$	10.73



EOG RESOURCES, INC. Crude Oil and Natural Gas Financial Commodity Derivative Contracts


EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. 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 February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

Midland Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2018
January 1, 2018 through February 28, 2018 (closed)	15,000	$	1.063
March 1, 2018 through December 31, 2018	15,000	1.063

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

EOG has entered into additional 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 February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.



Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2018
January 1, 2018 through February 28, 2018 (closed)	37,000	$	3.818
March 1, 2018 through December 31, 2018	37,000	3.818

On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain 2017 crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the table below. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 20, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl.



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


2017
January 1, 2017 through February 28, 2017 (closed)	35,000	$	50.04
March 1, 2017 through June 30, 2017 (closed)	30,000	50.05

2018
January 2018 (closed)	134,000	$	60.04
February 1, 2018 through December 31, 2018	134,000	60.04

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



Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

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

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



EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

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

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



EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

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



Definitions
Bbld		Barrels per day
$/Bbl		Dollars per barrel
MMBtud		Million British thermal units per day
$/MMBtu		Dollars per million British thermal units
NYMEX		U.S. New York Mercantile Exchange

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.

Direct ATROR

Based on Cash Flow and Time Value of Money

- Estimated future commodity prices and operating costs

- Costs incurred to drill, complete and equip a well, including facilities

Excludes Indirect Capital

- Gathering and Processing and other Midstream

- Land, Seismic, Geological and Geophysical

Payback ~12 Months on 100% Direct ATROR Wells

First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

- Eagle Ford, Bakken, Permian Facilities

- Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells



EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively (Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
	2017				2016				2015				2014				2013
Return on Capital Employed (ROCE) (Non-GAAP)

Net Interest Expense (GAAP)	$	274			$	282			$	237			$	201
Tax Benefit Imputed (based on 35%)	(96		)		(99		)		(83		)		(70		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	178			$	183			$	154			$	131

Net Income (Loss) (GAAP) - (b)	$	2,583			$	(1,097	)		$	(4,525	)		2,915
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules)	(1,934		)	(a)	204			(b)	4,559			(c)	(199		)	(d)
Adjusted Net Income (Loss) (Non-GAAP) - (c)	$	649			$	(893	)		$	34			$	2,716

Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d)	$	16,283			$	13,982			$	12,943			$	17,713			$	15,418
Less: Tax Reform Impact	(2,169		)		—				—				—				—
Total Stockholders' Equity (Non-GAAP) - (e)	$	14,114			$	13,982			$	12,943			$	17,713			$	15,418

Average Total Stockholders' Equity (GAAP) * - (f)	$	15,133			$	13,463			$	15,328			$	16,566

Average Total Stockholders' Equity (Non-GAAP) * - (g)	$	14,048			$	13,463			$	15,328			$	16,566

Current and Long-Term Debt (GAAP) - (h)	$	6,387			$	6,986			$	6,655			$	5,906			$	5,909
Less: Cash	(834		)		(1,600		)		(719		)		(2,087		)		(1,318		)
Net Debt (Non-GAAP) - (i)	$	5,553			$	5,386			$	5,936			$	3,819			$	4,591

Total Capitalization (GAAP) - (d) + (h)	$	22,670			$	20,968			$	19,598			$	23,619			$	21,327

Total Capitalization (Non-GAAP) - (e) + (i)	$	19,667			$	19,368			$	18,879			$	21,532			$	20,009

Average Total Capitalization (Non-GAAP) * - (j)	$	19,518			$	19,124			$	20,206			$	20,771

ROCE (GAAP Net Income) - [(a) + (b)] / (j)	14.1		%		-4.8		%		-21.6		%		14.7		%

ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j)	4.2		%		-3.7		%		0.9		%		13.7		%

Return on Equity (ROE)

ROE (GAAP) (GAAP Net Income) - (b) / (f)	17.1		%		-8.1		%		-29.5		%		17.6		%

ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g)	4.6		%		-6.6		%		0.2		%		16.4		%

* Average for the current and immediately preceding year

Adjustments to Net Income (Loss) (GAAP)



(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017:
		Year Ended December 31, 2017
		Before Tax			Income Tax Impact			After Tax
Adjustments:
Add:	Mark-to-Market Commodity Derivative Contracts Impact	$	(12	)	$	4		$	(8	)
Add:	Impairments of Certain Assets	261			(93		)	168
Add:	Net Losses on Asset Dispositions	99			(35		)	64
Add:	Legal Settlement - Early Lease Termination	10			(4		)	6
Add:	Joint Venture Transaction Costs	3			(1		)	2
Add:	Joint Interest Billings Deemed Uncollectible	5			(2		)	3
Less:	Tax Reform Impact	—			(2,169		)	(2,169		)
Total		$	366		$	(2,300	)	$	(1,934	)



(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016:
		Year Ended December 31, 2016
		Before Tax			Income Tax Impact			After Tax
Adjustments:
Add:	Mark-to-Market Commodity Derivative Contracts Impact	$	77		$	(28	)	$	49
Add:	Impairments of Certain Assets	321			(113		)	208
Less:	Net Gains on Asset Dispositions	(206		)	62			(144		)
Add:	Trinidad Tax Settlement	—			43			43
Add:	Voluntary Retirement Expense	42			(15		)	27
Add:	Acquisition - State Apportionment Change	—			16			16
Add:	Acquisition Costs	5			—			5
Total		$	239		$	(35	)	$	204



(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015:
		Year Ended December 31, 2015
		Before Tax		Income Tax Impact			After Tax
Adjustments:
Add:	Mark-to-Market Commodity Derivative Contracts Impact	$	668	$	(238	)	$	430
Add:	Impairments of Certain Assets	6,308		(2,183		)	4,125
Less:	Texas Margin Tax Rate Reduction	—		(20		)	(20		)
Add:	Legal Settlement - Early Leasehold Termination	19		(6		)	13
Add:	Severance Costs	9		(3		)	6
Add:	Net Losses on Asset Dispositions	9		(4		)	5
Total		$	7,013	$	(2,454	)	$	4,559



(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014:
		Year Ended December 31, 2014
		Before Tax			Income Tax Impact			After Tax
Adjustments:
Less:	Mark-to-Market Commodity Derivative Contracts Impact	$	(800	)	$	285		$	(515	)
Add:	Impairments of Certain Assets	824			(271		)	553
Less:	Net Gains on Asset Dispositions	(508		)	21			(487		)
Add:	Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years	—			250			250
Total		$	(484	)	$	285		$	(199	)



EOG RESOURCES, INC. First Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing

(a) First Quarter and Full Year 2018 Forecast

The forecast items for the first quarter and full year 2018 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

(b) Benchmark Commodity Pricing

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

	Estimated Ranges (Unaudited)
	1Q 2018			Full Year 2018
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States	350.0	-	360.0	387.0	-	401.0
Trinidad	0.5	-	0.7	0.4	-	0.6
Other International	0.0	-	5.0	2.0	-	4.0
Total	350.5	-	365.7	389.4	-	405.6

Natural Gas Liquids Volumes (MBbld)
Total	93.0	-	103.0	100.0	-	110.0

Natural Gas Volumes (MMcfd)
United States	825	-	865	900	-	950
Trinidad	280	-	310	250	-	290
Other International	25	-	35	28	-	38
Total	1,130	-	1,210	1,178	-	1,278

Crude Oil Equivalent Volumes (MBoed)
United States	580.5	-	607.2	637.0	-	669.3
Trinidad	47.2	-	52.4	42.1	-	48.9
Other International	4.2	-	10.8	6.7	-	10.3
Total	631.9	-	670.4	685.8	-	728.5



		Estimated Ranges (Unaudited)
		1Q 2018							Full Year 2018
Operating Costs
Unit Costs ($/Boe)
Lease and Well		$	4.70		-	$	5.10		$	4.20		-	$	4.80
Transportation Costs		$	3.00		-	$	3.50		$	2.75		-	$	3.25
Depreciation, Depletion and Amortization		$	13.00		-	$	13.40		$	13.10		-	$	13.50

Expenses ($MM)
Exploration, Dry Hole and Impairment		$	90		-	$	120		$	375		-	$	425
General and Administrative		$	100		-	$	110		$	415		-	$	445
Gathering and Processing		$	95		-	$	105		$	430		-	$	470
Capitalized Interest		$	6		-	$	8		$	27		-	$	32
Net Interest		$	60		-	$	62		$	234		-	$	242

Taxes Other Than Income (% of Wellhead Revenue)			6.6	%	-		7.0	%		6.5	%	-		6.9	%

Income Taxes
Effective Rate			20	%	-		25	%		20	%	-		25	%
Current Taxes ($MM)		$	(90	)	-	$	(55	)	$	(310	)	-	$	(270	)

Capital Expenditures (Excluding Acquisitions, $MM)
Exploration and Development, Excluding Facilities									$	4,500		-	$	4,800
Exploration and Development Facilities									$	600		-	$	650
Gathering, Processing and Other									$	300		-	$	350

Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI		$	0.00		-	$	1.50		$	(1.00	)	-	$	1.00
Trinidad - above (below) WTI		$	(11.00	)	-	$	(9.00	)	$	(11.00	)	-	$	(9.00	)
Other International - above (below) WTI		$	0.00		-	$	2.00		$	0.00		-	$	2.00

Natural Gas Liquids
Realizations as % of WTI			39	%	-		45	%		40	%	-		46	%

Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub		$	(0.40	)	-	$	0.00		$	(0.60	)	-	$	0.00

Realizations
Trinidad		$	2.50		-	$	2.90		$	2.15		-	$	2.75
Other International		$	4.15		-	$	4.65		$	4.00		-	$	5.00

Definitions
$/Bbl	U.S. Dollars per barrel
$/Boe	U.S. Dollars per barrel of oil equivalent
$/Mcf	U.S. Dollars per thousand cubic feet
$MM	U.S. Dollars in millions
MBbld	Thousand barrels per day
MBoed	Thousand barrels of oil equivalent per day
MMcfd	Million cubic feet per day
NYMEX	U.S. New York Mercantile Exchange
WTI	West Texas Intermediate



EOG RESOURCES, INC. Fourth Quarter 2017 Well Results by Play (Unaudited)

	Wells Completed			Initial 30-Day Average Production Rate
	Gross	Net	Lateral Length (ft)	Crude Oil and Condensate (Bbld) ^(A)	Natural Gas Liquids (Bbld) ^(A)	Natural Gas (MMcfd) ^(A)	Crude Oil Equivalent (Boed) ^(B)
Delaware Basin
Wolfcamp	51	45	6,000	1,410	310	2.5	2,145
Bone Spring	9	9	6,700	1,085	160	1.3	1,470
Leonard	5	5	8,700	1,230	265	2.2	1,865

Powder River Basin Turner	9	7	7,700	990	375	4.7	2,150

DJ Basin Codell	3	2	9,100	950	105	0.4	1,120

South Texas Eagle Ford	74	70	7,400	1,525	195	1.1	1,915

South Texas Austin Chalk	4	4	5,300	2,280	430	2.5	3,130

(A) Barrels per day or million cubic feet per day, as applicable.
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.