EXHIBIT 99.1

February 26, 2019

EOG Resources Reports Fourth Quarter and Full Year 2018 Results and Announces 2019 Capital Program

• Earns Record Net Income in 2018 and Generates Significant Net Cash from Operating Activities and Free Cash Flow

• Exceeds Fourth Quarter Crude Oil and NGL Production Target Midpoints

• Increases Proved Reserves by 16% and Replaces 238% of 2018 Production at Sub-$10 Finding Cost

• Targets Improved Capital Efficiency, Significant Investment in High-Quality New Drilling Potential and 12-16% U.S. Crude Oil Volume Growth in 2019, Funded with Net Cash from Operating Activities at $50 Oil

HOUSTON - EOG Resources, Inc. (EOG) today reported fourth quarter 2018 net income of $893 million, or $1.54 per share. This compares to fourth quarter 2017 net income of $2.4 billion, or $4.20 per share. For the full year 2018, EOG reported a company record net income of $3.4 billion, or $5.89 per share, compared to $2.6 billion, or $4.46 per share, for the full year 2017. Net cash from operating activities for the fourth quarter and full year 2018 was $2.1 billion and $7.8 billion, respectively.

Adjusted non-GAAP net income for the fourth quarter 2018 was $718 million, or $1.24 per share, compared to adjusted non-GAAP net income of $401 million, or $0.69 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2018 was $3.2 billion, or $5.54 per share, compared to adjusted non-GAAP net income of $648 million, or $1.12 per share, for the full year 2017. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Fourth Quarter and Full Year 2018 Review

EOG delivered exceptional financial and operating performance in 2018. The company generated record net income and free cash flow, while ending the year with strong improvements in well productivity and additional cost reductions. Total company crude oil volumes grew 19 percent to 399,900 barrels of oil per day (Bopd). Natural gas liquids production increased 31 percent, while natural gas volumes grew 11 percent, contributing to total company production growth of 18 percent.

In the fourth quarter 2018, EOG exceeded the high end of its target range for U.S. crude oil volumes by producing 430,300 Bopd, an increase of 17 percent compared to the same prior year period. Per-unit operating expenses declined during the fourth quarter 2018 compared to the same prior year period. Lower general and administrative expenses, transportation costs and depreciation, depletion and amortization expenses each contributed to the overall cost reduction.

EOG generated $2.1 billion of discretionary cash flow and incurred total expenditures of $1.5 billion in the fourth quarter 2018. After considering cash exploration and development expenditures, excluding acquisitions, of $1.3 billion and dividend payments of $127 million, the company generated free cash flow during the fourth quarter of $637 million. For the full year 2018 EOG generated a company record $1.7 billion of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

“Our goal at EOG is to be one of the best companies in the S&P 500. Our stellar 2018 performance delivered a premium combination of high returns and double-digit production growth while generating record free cash flow,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “Our 2018 results show that we can be competitive with the best companies across all sectors, and we remain relentlessly focused on further improving our cost structure and operating performance.”

2019 Capital Plan

EOG’s capital plan is custom-designed each year to increase returns and capital efficiencies. In 2019, EOG is allocating more capital to opportunistic, high quality new drilling potential and somewhat less capital to drilling in established areas. The company’s disciplined growth strategy emphasizes generating free cash flow while lowering well costs and per-unit operating expenses and driving improvement in well productivity. Retaining high-quality equipment and crews during the fourth quarter of 2018 positioned the company to further improve efficiencies and returns in 2019.

EOG expects to grow U.S. crude oil production by 12 to 16 percent, fund capital investment and pay the dividend with net cash from operating activities in 2019 at $50 oil. Exploration and development expenditures for 2019 are expected to range from $6.1 to $6.5 billion, including facilities and gathering, processing and other expenditures, excluding acquisitions and non-cash exchanges.

EOG expects to complete approximately 740 net wells in 2019 compared to 763 net wells in 2018. Activity will remain focused in EOG’s highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and Bakken. The company’s investment in new potential areas in the United States includes spending for leasing and related infrastructure to drill wells in a number of new prospects in 2019.

“EOG’s disciplined 2019 capital plan delivers improved capital efficiency and strong high-return growth while making investments in new organic high-quality drilling potential to improve the future performance of the company,” Thomas said. “Our focus on innovation and operational execution, as well as our investment in new drilling potential, will continue to increase the quality of EOG’s premium portfolio. EOG is poised to further improve its position as one of the lowest cost oil producers in the global market, able to create shareholder value through commodity price cycles.”

Operating Highlights

EOG completed 262 net wells in the Delaware Basin and increased crude oil production 47% to 126,800 Bopd in 2018. The company made significant progress during 2018 in improving well productivity and reducing well costs. EOG refined spacing and development patterns, reduced drilling days and applied new completion technology designed to lower costs and improve well productivity.

EOG continues to drive growth and operating efficiencies in its premier South Texas Eagle Ford asset. In 2018, the company grew crude oil production 9% to 171,000 Bopd. Of the 304 net wells completed in 2018, EOG drilled a total of 65 wells with lateral lengths greater than 10,000 feet. These wells included the Slytherin C#3H, which, at 13,500 feet, was a company record in the Eagle Ford.

EOG’s Powder River Basin and Wyoming DJ Basin activity both contributed to the company’s 2018 crude oil production growth. In the Powder River Basin, the company brought eight wells on line during the fourth quarter targeting the Turner, Mowry and Parkman formations. The company plans to add infrastructure and further delineate the field and test additional targets in 2019 to be positioned to execute a more robust development program in the Niobrara and Mowry in 2020 and beyond. In the Wyoming DJ Basin, EOG generated further cost reductions during 2018 through efficiency improvements in drilling, completion and production operations. The company brought 20 wells to sales in the fourth quarter, all targeting the Codell formation. EOG expects further crude oil production growth from its high rate of return drilling in the DJ Basin in 2019.

EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window, where it brought five wells on line in the fourth quarter. The company made significant progress in reducing well costs during 2018, and, as a result, has lowered its 2019 well cost target to $7.6 million.

In the Williston Basin, EOG realized significant operational improvements in 2018. The company drilled 20 net wells with an average treated lateral length of 9,500 feet per well. Efficient drilling performance delivered, on average, an additional 1,000 feet of lateral length per well in 2018 for the same cost as 2017. EOG’s Austin 45-1113H well set a company record in the basin with a spud-to-total depth time of 8.4 days.

Reserves

At year-end 2018, total company net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), an increase of 16 percent compared to year-end 2017. Net proved reserve additions from all sources, excluding revisions due to price, replaced 238 percent of EOG’s 2018 production at a finding and development cost of $9.33 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 35 MMBoe and asset divestitures decreased net proved reserves by 11 MMBoe. For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

For the 31st consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.

Financial Review

At December 31, 2018, EOG’s total debt outstanding was $6.1 billion for a debt-to-total capitalization ratio of 24 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $4.5 billion for a net debt-to-total capitalization ratio of 19 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG completed its previously announced agreement to divest all of its U.K. operations in the fourth quarter 2018. Proceeds from the U.K. divestment and other asset sales in 2018 totaled $227 million.

Fourth Quarter 2018 Results Webcast

Wednesday, February 27, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)

Webcast will be available on EOG website for one year.

http://investors.eogresources.com/Investors

About EOG

EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.

Investor Contacts

David Streit 713-571-4902

Neel Panchal 713-571-4884

John Wagner 713-571-4404

Media and Investor Contact

Kimberly Ehmer 713-571-4676

This press release may include 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 expenditures, generate 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. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Any such 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 such measures and estimates. 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, storage, 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; climate change and other 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 tubulars) 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, storage 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;

• geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, 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 cybersecurity breaches; and

• the other factors described under ITEM 1A, Risk Factors, on pages 13 through 22 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 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 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.

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 or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, “resource potential” and/or other estimated reserves or estimated resources 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, 2018, 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,
	2018		2017		2018		2017
Operating Revenues and Other	$	4,574.5	$	3,340.4	$	17,275.4	$	11,208.3
Net Income	$	892.8	$	2,430.5	$	3,419.0	$	2,582.6
Net Income Per Share
Basic	$	1.55	$	4.22	$	5.93	$	4.49
Diluted	$	1.54	$	4.20	$	5.89	$	4.46
Average Number of Common Shares
Basic		577.0		575.4		576.6		574.6
Diluted		580.3		579.2		580.4		578.7

Summary Income Statements (Unaudited; in thousands, except per share data)
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2018			2017			2018			2017
Operating Revenues and Other
Crude Oil and Condensate	$	2,383,326		$	1,929,471		$	9,517,440		$	6,256,396
Natural Gas Liquids		266,037			249,172			1,127,510			729,561
Natural Gas		389,213			246,922			1,301,537			921,934
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		132,095			(45,032	)		(165,640	)		19,828
Gathering, Processing and Marketing		1,331,105			1,008,385			5,230,355			3,298,087
Gains (Losses) on Asset Dispositions, Net		79,904			(65,220	)		174,562			(99,096	)
Other, Net		(7,144	)		16,741			89,635			81,610
Total		4,574,536			3,340,439			17,275,399			11,208,320
Operating Expenses
Lease and Well		346,442			281,941			1,282,678			1,044,847
Transportation Costs		196,095			191,717			746,876			740,352
Gathering and Processing Costs		112,396			43,295			436,973			148,775
Exploration Costs		33,862			22,941			148,999			145,342
Dry Hole Costs		145			4,532			5,405			4,609
Impairments		186,087			153,442			347,021			479,240
Marketing Costs		1,349,416			1,009,566			5,203,243			3,330,237
Depreciation, Depletion and Amortization		919,963			881,745			3,435,408			3,409,387
General and Administrative		116,904			117,005			426,969			434,467
Taxes Other Than Income		190,086			158,343			772,481			544,662
Total		3,451,396			2,864,527			12,806,053			10,281,918
Operating Income		1,123,140			475,912			4,469,346			926,402
Other Income, Net		21,220			803			16,704			9,152
Income Before Interest Expense and Income Taxes		1,144,360			476,715			4,486,050			935,554
Interest Expense, Net		56,020			63,362			245,052			274,372
Income Before Income Taxes		1,088,340			413,353			4,240,998			661,182
Income Tax Provision (Benefit)		195,572			(2,017,115	)		821,958			(1,921,397	)
Net Income	$	892,768		$	2,430,468		$	3,419,040		$	2,582,579
Dividends Declared per Common Share	$	0.2200		$	0.1675		$	0.8100		$	0.6700

EOG RESOURCES, INC. Operating Highlights (Unaudited)
	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2018			2017		2018			2017
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States		430.3			366.9		394.8			335.0
Trinidad		0.8			1.1		0.8			0.9
Other International (B)		4.5			0.1		4.3			0.8
Total		435.6			368.1		399.9			336.7
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States	$	59.37		$	56.95	$	65.16		$	50.91
Trinidad		51.80			46.56		57.26			42.30
Other International (B)		70.44			45.72		71.45			57.20
Composite		59.47			56.97		65.21			50.91
Natural Gas Liquids Volumes (MBbld) (A)
United States		122.8			100.6		116.1			88.4
Other International (B)		—			—		—			—
Total		122.8			100.6		116.1			88.4
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States	$	23.54		$	26.92	$	26.60		$	22.61
Other International (B)		—			—		—			—
Composite		23.54			26.92		26.60			22.61
Natural Gas Volumes (MMcfd) (A)
United States		974			829		923			765
Trinidad		230			299		266			313
Other International (B)		32			32		30			25
Total		1,236			1,160		1,219			1,103
Average Natural Gas Prices ($/Mcf) (C)
United States	$	3.50		$	2.17	$	2.88		$	2.20
Trinidad		3.03			2.52		2.94			2.38
Other International (B)		4.02			4.23		4.08			3.89
Composite		3.42	(D)		2.31		2.92	(D)		2.29
Crude Oil Equivalent Volumes (MBoed) (E)
United States		715.5			605.6		664.7			551.0
Trinidad		39.0			51.0		45.1			53.0
Other International (B)		10.0			5.4		9.4			4.9
Total		764.5			662.0		719.2			608.9
Total MMBoe (E)		70.3			60.9		262.5			222.3

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

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

(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2018).

(D) Includes positive revenue adjustments of $0.49 per Mcf and $0.44 per Mcf for the three and twelve months ended December 31, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year period ended December 31, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas Revenues.

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

EOG RESOURCES, INC. Summary Balance Sheets (Unaudited; in thousands, except share data)
	December 31,			December 31,
	2018			2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,555,634		$	834,228
Accounts Receivable, Net		1,915,215			1,597,494
Inventories		859,359			483,865
Assets from Price Risk Management Activities		23,806			7,699
Income Taxes Receivable		427,909			113,357
Other		275,467			242,465
Total		5,057,390			3,279,108
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		57,330,016			52,555,741
Other Property, Plant and Equipment		4,220,665			3,960,759
Total Property, Plant and Equipment		61,550,681			56,516,500
Less: Accumulated Depreciation, Depletion and Amortization		(33,475,162	)		(30,851,463	)
Total Property, Plant and Equipment, Net		28,075,519			25,665,037
Deferred Income Taxes		777			17,506
Other Assets		800,788			871,427
Total Assets	$	33,934,474		$	29,833,078
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,239,850		$	1,847,131
Accrued Taxes Payable		214,726			148,874
Dividends Payable		126,971			96,410
Liabilities from Price Risk Management Activities		—			50,429
Current Portion of Long-Term Debt		913,093			356,235
Other		233,724			226,463
Total		3,728,364			2,725,542
Long-Term Debt		5,170,169			6,030,836
Other Liabilities		1,258,355			1,275,213
Deferred Income Taxes		4,413,398			3,518,214
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 580,408,117 Shares and 578,827,768 Shares Issued at December 31, 2018 and 2017, respectively		205,804			205,788
Additional Paid in Capital		5,658,794			5,536,547
Accumulated Other Comprehensive Loss		(1,358	)		(19,297	)
Retained Earnings		13,543,130			10,593,533
Common Stock Held in Treasury, 385,042 Shares and 350,961 Shares at December 31, 2018 and 2017, respectively		(42,182	)		(33,298	)
Total Stockholders' Equity		19,364,188			16,283,273
Total Liabilities and Stockholders' Equity	$	33,934,474		$	29,833,078

EOG RESOURCES, INC. Summary Statements of Cash Flows (Unaudited; in thousands)
	Twelve Months Ended
	December 31,
	2018			2017
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	3,419,040		$	2,582,579
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,435,408			3,409,387
Impairments		347,021			479,240
Stock-Based Compensation Expenses		155,337			133,849
Deferred Income Taxes		894,156			(1,473,872	)
(Gains) Losses on Asset Dispositions, Net		(174,562	)		99,096
Other, Net		7,066			6,546
Dry Hole Costs		5,405			4,609
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		165,640			(19,828	)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(258,906	)		7,438
Other, Net		3,108			1,204
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(368,180	)		(392,131	)
Inventories		(395,408	)		(174,548	)
Accounts Payable		439,347			324,192
Accrued Taxes Payable		(92,461	)		(63,937	)
Other Assets		(125,435	)		(658,609	)
Other Liabilities		10,949			(89,871	)
Changes in Components of Working Capital Associated with Investing and Financing Activities		301,083			89,992
Net Cash Provided by Operating Activities		7,768,608			4,265,336
Investing Cash Flows
Additions to Oil and Gas Properties		(5,839,294	)		(3,950,918	)
Additions to Other Property, Plant and Equipment		(237,181	)		(173,324	)
Proceeds from Sales of Assets		227,446			226,768
Other Investing Activities		(19,993	)		—
Changes in Components of Working Capital Associated with Investing Activities		(301,140	)		(89,935	)
Net Cash Used in Investing Activities		(6,170,162	)		(3,987,409	)
Financing Cash Flows
Long-Term Debt Repayments		(350,000	)		(600,000	)
Dividends Paid		(438,045	)		(386,531	)
Treasury Stock Purchased		(63,456	)		(63,408	)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		20,560			20,840
Repayment of Capital Lease Obligation		(8,219	)		(6,555	)
Changes in Components of Working Capital Associated with Financing Activities		57			(57	)
Net Cash Used in Financing Activities		(839,103	)		(1,035,711	)
Effect of Exchange Rate Changes on Cash		(37,937	)		(7,883	)
Increase (Decrease) in Cash and Cash Equivalents		721,406			(765,667	)
Cash and Cash Equivalents at Beginning of Period		834,228			1,599,895
Cash and Cash Equivalents at End of Period	$	1,555,634		$	834,228

EOG RESOURCES, INC. Fourth Quarter 2018 Well Results by Play (Unaudited)
	Wells Online			Initial Gross 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	42	37	7,000	1,950	600	3.7	3,150
Bone Spring	13	11	5,300	1,550	300	1.9	2,150
Leonard	2	1	4,600	1,200	550	3.7	2,350
South Texas Eagle Ford	82	78	7,300	1,300	150	0.8	1,600
South Texas Austin Chalk	6	5	5,500	2,650	550	2.6	3,650
Powder River Basin
Turner	4	3	9,700	800	200	2.4	1,400
Mowry	2	2	9,200	700	450	5.5	2,050
DJ Basin Codell	20	10	9,600	700	50	0.3	800
Williston Basin Bakken/Three Forks	7	5	10,100	550	25	0.1	600
Anadarko Basin Woodford Oil Window	5	4	9,200	600	75	0.4	750
(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.

EOG RESOURCES, INC. Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) To Net Income (GAAP) (Unaudited; in thousands, except per share data)
The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (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 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, 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 certain joint interest billings deemed uncollectible in 2017 and to eliminate certain adjustments in 2018 and 2017 related to the 2017 U.S. tax reform. 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 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												Three Months Ended
		December 31, 2018												December 31, 2017
		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 (GAAP)	$	1,088,340		$	(195,572	)	$	892,768		$	1.54		$	413,353	$	2,017,115		$	2,430,468		$	4.20
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		(132,095	)		29,096			(102,999	)		(0.18	)		45,032		(16,142	)		28,890			0.05
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(78,678	)		17,330			(61,348	)		(0.11	)		2,708		(971	)		1,737			—
Add: Net (Gains) Losses on Asset Dispositions		(79,904	)		13,625			(66,279	)		(0.11	)		65,220		(23,315	)		41,905			0.07
Add: Impairments		131,795			(29,031	)		102,764			0.18			100,304		(35,954	)		64,350			0.11
Add: Joint Interest Billings Deemed Uncollectible		—			—			—			—			4,528		(1,623	)		2,905			0.01
Less: Tax Reform Impact		—			(46,684	)		(46,684	)		(0.08	)		—		(2,169,376	)		(2,169,376	)		(3.75	)
Adjustments to Net Income		(158,882	)		(15,664	)		(174,546	)		(0.30	)		217,792		(2,247,381	)		(2,029,589	)		(3.51	)
Adjusted Net Income (Non-GAAP)	$	929,458		$	(211,236	)	$	718,222		$	1.24		$	631,145	$	(230,266	)	$	400,879		$	0.69
Average Number of Common Shares (GAAP)
Basic											577,035											575,394
Diluted											580,288											579,203

		Twelve Months Ended												Twelve Months Ended
		December 31, 2018												December 31, 2017
		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 (GAAP)	$	4,240,998		$	(821,958	)	$	3,419,040		$	5.89		$	661,182		$	1,921,397		$	2,582,579		$	4.46
Adjustments:
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts		165,640			(36,486	)		129,154			0.22			(19,828	)		7,107			(12,721	)		(0.02	)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(258,906	)		57,029			(201,877	)		(0.35	)		7,438			(2,666	)		4,772			0.01
Add: Net (Gains) Losses on Asset Dispositions		(174,562	)		37,860			(136,702	)		(0.24	)		99,096			(35,270	)		63,826			0.11
Add: Impairments		152,671			(33,629	)		119,042			0.21			261,452			(93,718	)		167,734			0.29
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		—			(110,335	)		(110,335	)		(0.19	)		—			(2,169,376	)		(2,169,376	)		(3.75	)
Adjustments to Net Income		(115,157	)		(85,561	)		(200,718	)		(0.35	)		365,944			(2,300,298	)		(1,934,354	)		(3.34	)
Adjusted Net Income (Non-GAAP)	$	4,125,841		$	(907,519	)	$	3,218,322		$	5.54		$	1,027,126		$	(378,901	)	$	648,225		$	1.12
Average Number of Common Shares (GAAP)
Basic											576,578												574,620
Diluted											580,441												578,693

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, 2018 and 2017 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), Other Non-Current Income Taxes - Net Receivable (Payable), 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 three months and twelve months ended December 31, 2018. EOG management uses this information for comparative purposes within the industry.
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2018			2017			2018			2017
Net Cash Provided by Operating Activities (GAAP)	$	2,085,228		$	1,327,548		$	7,768,608		$	4,265,336
Adjustments:
Exploration Costs (excluding Stock-Based Compensation Expenses)		27,270			16,420			123,986			122,688
Other Non-Current Income Taxes - Net Receivable (Payable)		86,572			(513,404	)		148,993			(513,404	)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(185,349	)		366,686			368,180			392,131
Inventories		108,591			156,874			395,408			174,548
Accounts Payable		98,178			(211,298	)		(439,347	)		(324,192	)
Accrued Taxes Payable		55,570			13,970			92,461			63,937
Other Assets		22,101			574,669			125,435			658,609
Other Liabilities		(25,725	)		20,647			(10,949	)		89,871
Changes in Components of Working Capital Associated with Investing and Financing Activities		(205,599	)		(210,365	)		(301,083	)		(89,992	)
Discretionary Cash Flow (Non-GAAP)	$	2,066,837		$	1,541,747		$	8,271,692		$	4,839,532
Discretionary Cash Flow (Non-GAAP) - Percentage Increase		34	%					71	%
Discretionary Cash Flow (Non-GAAP)	$	2,066,837					$	8,271,692
Less:
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) (a)		(1,302,999	)					(6,172,950	)
Dividends Paid (GAAP)		(126,970	)					(438,045	)
Free Cash Flow (Non-GAAP)	$	636,868					$	1,660,697

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and twelve months ended December 31, 2018:
Total Expenditures (GAAP)	$	1,504,438		$	6,706,359
Less:
Asset Retirement Costs		(27,910	)		(69,699	)
Non-Cash Expenditures of Other Property, Plant and Equipment		(547	)		(49,484	)
Non-Cash Acquisition Costs of Unproved Properties		(128,719	)		(290,542	)
Acquisition Costs of Proved Properties		(44,263	)		(123,684	)
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)	$	1,302,999		$	6,172,950

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 (GAAP) (Unaudited; in thousands)
The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (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 (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 (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,
	2018			2017			2018			2017
Net Income (GAAP)	$	892,768		$	2,430,468		$	3,419,040		$	2,582,579
Adjustments:
Interest Expense, Net		56,020			63,362			245,052			274,372
Income Tax Provision (Benefit)		195,572			(2,017,115	)		821,958			(1,921,397	)
Depreciation, Depletion and Amortization		919,963			881,745			3,435,408			3,409,387
Exploration Costs		33,862			22,941			148,999			145,342
Dry Hole Costs		145			4,532			5,405			4,609
Impairments		186,087			153,442			347,021			479,240
EBITDAX (Non-GAAP)		2,284,417			1,539,375			8,422,883			4,974,132
Total (Gains) Losses on MTM Commodity Derivative Contracts		(132,095	)		45,032			165,640			(19,828	)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(78,678	)		2,708			(258,906	)		7,438
(Gains) Losses on Asset Dispositions, Net		(79,904	)		65,220			(174,562	)		99,096
Adjusted EBITDAX (Non-GAAP)	$	1,993,740		$	1,652,335		$	8,155,055		$	5,060,838
Adjusted EBITDAX (Non-GAAP) - Percentage Increase		21	%					61	%

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,
	2018			2017
Total Stockholders' Equity - (a)	$	19,364		$	16,283
Current and Long-Term Debt (GAAP) - (b)		6,083			6,387
Less: Cash		(1,556	)		(834	)
Net Debt (Non-GAAP) - (c)		4,527			5,553
Total Capitalization (GAAP) - (a) + (b)	$	25,447		$	22,670
Total Capitalization (Non-GAAP) - (a) + (c)	$	23,891		$	21,836
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]		24	%		28	%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]		19	%		25	%

EOG RESOURCES, INC.
Reserves Supplemental Data
(Unaudited)
2018 NET PROVED RESERVES RECONCILIATION SUMMARY
	United States			Trinidad			Other International			Total
CRUDE OIL AND CONDENSATE (MMBbl)
Beginning Reserves	1,304.1			0.9			8.0			1,313.0
Revisions	(13.2		)	(0.2		)	—			(13.4		)
Purchases in Place	2.7			—			—			2.7
Extensions, Discoveries and Other Additions	383.0			—			—			383.0
Sales in Place	(0.8		)	—			(6.3		)	(7.1		)
Production	(144.1		)	(0.3		)	(1.5		)	(145.9		)
Ending Reserves	1,531.7			0.4			0.2			1,532.3
NATURAL GAS LIQUIDS (MMBbl)
Beginning Reserves	503.5			—			—			503.5
Revisions	23.9			—			—			23.9
Purchases in Place	2.0			—			—			2.0
Extensions, Discoveries and Other Additions	127.4			—			—			127.4
Sales in Place	—			—			—			—
Production	(42.5		)	—			—			(42.5		)
Ending Reserves	614.3			—			—			614.3
NATURAL GAS (Bcf)
Beginning Reserves	3,898.5			313.4			51.2			4,263.1
Revisions	(127.2		)	20.7			15.0			(91.5		)
Purchases in Place	41.3			—			—			41.3
Extensions, Discoveries and Other Additions	951.4			—			4.6			956.0
Sales in Place	(22.2		)	—			—			(22.2		)
Production	(351.2		)	(97.1		)	(11.2		)	(459.5		)
Ending Reserves	4,390.6			237.0			59.6			4,687.2
OIL EQUIVALENTS (MMBoe)
Beginning Reserves	2,457.3			53.1			16.6			2,527.0
Revisions	(10.5		)	3.3			2.5			(4.7		)
Purchases in Place	11.6			—			—			11.6
Extensions, Discoveries and Other Additions	669.0			—			0.7			669.7
Sales in Place	(4.5		)	—			(6.3		)	(10.8		)
Production	(245.1		)	(16.5		)	(3.4		)	(265.0		)
Ending Reserves	2,877.8			39.9			10.1			2,927.8
Net Proved Developed Reserves (MMBoe)
At December 31, 2017	1,300.7			50.8			12.8			1,364.3
At December 31, 2018	1,503.4			37.7			7.0			1,548.1
2018 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)
	United States			Trinidad			Other International			Total
Acquisition Cost of Unproved Properties	$	486.0		$	1.3		$	—		$	487.3
Exploration Costs	157.2			22.5			13.9			193.6
Development Costs	5,515.4			(0.8		)	30.8			5,545.4
Total Drilling	6,158.6			23.0			44.7			6,226.3
Acquisition Cost of Proved Properties	123.7			—			—			123.7
Asset Retirement Costs	90.0			(12.1		)	(8.2		)	69.7
Total Exploration and Development Expenditures	6,372.3			10.9			36.5			6,419.7
Gathering, Processing and Other	286.0			0.4			0.3			286.7
Total Expenditures	6,658.3			11.3			36.8			6,706.4
Proceeds from Sales in Place	(53.3		)	—			(174.1		)	(227.4		)
Net Expenditures	$	6,605.0		$	11.3		$	(137.3	)	$	6,479.0
RESERVE REPLACEMENT COSTS ($ / Boe) *
All-in Total, Net of Revisions	$	8.84		$	6.97		$	13.97		$	8.85
All-in Total, Excluding Revisions Due to Price	$	9.32		$	6.97		$	13.97		$	9.33
RESERVE REPLACEMENT *
Drilling Only	273		%	0		%	21		%	253		%
All-in Total, Net of Revisions and Dispositions	272		%	20		%	-91		%	251		%
All-in Total, Excluding Revisions Due to Price	257		%	20		%	-91		%	238		%
All-in Total, Liquids	281		%	-67		%	-420		%	275		%
* 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 data)
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and 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 “Drilling Only” and “All-In”, which reflects total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or 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, 2018
	United States			Trinidad			Other International			Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	6,372.3		$	10.9		$	36.5		$	6,419.7
Less: Asset Retirement Costs	(90.0		)	12.1			8.2			(69.7		)
Non-Cash Acquisition Costs of Unproved Properties	(290.5		)	—			—			(290.5		)
Total Acquisition Costs of Proved Properties	(123.7		)	—			—			(123.7		)
Total Exploration and Development Expenditures (Non-GAAP) (a)	$	5,868.1		$	23.0		$	44.7		$	5,935.8
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	6,372.3		$	10.9		$	36.5		$	6,419.7
Less: Asset Retirement Costs	(90.0		)	12.1			8.2			(69.7		)
Non-Cash Acquisition Costs of Unproved Properties	(290.5		)	—			—			(290.5		)
Non-Cash Acquisition Costs of Proved Properties	(70.9		)	—			—			(70.9		)
Total Exploration and Development Expenditures (Non-GAAP) (b)	$	5,920.9		$	23.0		$	44.7		$	5,988.6
Total Expenditures (GAAP)	$	6,658.3		$	11.3		$	36.8		$	6,706.4
Less: Asset Retirement Costs	(90.0		)	12.1			8.2			(69.7		)
Non-Cash Acquisition Costs of Unproved Properties	(290.5		)	—			—			(290.5		)
Non-Cash Acquisition Costs of Proved Properties	(70.9		)	—			—			(70.9		)
Non-Cash Capital - Other Miscellaneous	(49.5		)	—			—			(49.5		)
Total Cash Expenditures (Non-GAAP)	$	6,157.4		$	23.4		$	45.0		$	6,225.8
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price (c)	34.8			—			—			34.8
Revisions Other Than Price	(45.3		)	3.3			2.5			(39.5		)
Purchases in Place	11.6			—			—			11.6
Extensions, Discoveries and Other Additions (d)	669.0			—			0.7			669.7
Total Proved Reserve Additions (e)	670.1			3.3			3.2			676.6
Sales in Place	(4.5		)	—			(6.3		)	(10.8		)
Net Proved Reserve Additions From All Sources (f)	665.6			3.3			(3.1		)	665.8
Production (g)	245.1			16.5			3.4			265.0
RESERVE REPLACEMENT COSTS ($ / Boe)
Total Drilling, Before Revisions (a / d)	$	8.77		$	—		$	63.86		$	8.86
All-in Total, Net of Revisions (b / e)	$	8.84		$	6.97		$	13.97		$	8.85
All-in Total, Excluding Revisions Due to Price (b / (e - c))	$	9.32		$	6.97		$	13.97		$	9.33
RESERVE REPLACEMENT
Drilling Only (d / g)	273		%	0		%	21		%	253		%
All-in Total, Net of Revisions and Dispositions (f / g)	272		%	20		%	-91		%	251		%
All-in Total, Excluding Revisions Due to Price ((f - c) / g)	257		%	20		%	-91		%	238		%

For the Twelve Months Ended December 31, 2018
	United States		Trinidad		Other International		Total
Net Proved Reserve Additions From All Sources - Liquids (MMBbl)
Revisions	10.7		(0.2	)	—		10.5
Purchases in Place	4.7		—		—		4.7
Extensions, Discoveries and Other Additions (h)	510.4		—		—		510.4
Total Proved Reserve Additions	525.8		(0.2	)	—		525.6
Sales in Place	(0.8	)	—		(6.3	)	(7.1	)
Net Proved Reserve Additions From All Sources (i)	525.0		(0.2	)	(6.3	)	518.5
Production (j)	186.6		0.3		1.5		188.4
RESERVE REPLACEMENT - LIQUIDS
Drilling Only (h / j)	274	%	0	%	0	%	271	%
All-in Total, Net of Revisions and Dispositions (i / j)	281	%	-67	%	-420	%	275	%

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, 2018
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)	Total
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	6,419.7
Less: Asset Retirement Costs	(69.7		)
Acquisition Costs of Unproved Properties	(487.3		)
Acquisition Costs of Proved Properties	(123.7		)
Drillbit Exploration and Development Expenditures (Non-GAAP) (j)	$	5,739.0
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe)	669.7
Add: Conversion of Proved Undeveloped Reserves to Proved Developed	265.7
Less: Proved Undeveloped Extensions and Discoveries	(490.7		)
Proved Developed Reserves - Extensions and Discoveries (MMBoe)	444.7
Total Proved Reserves - Revisions (MMBoe)	(4.7		)
Less: Proved Undeveloped Reserves - Revisions	8.2
Proved Developed - Revisions Due to Price	(31.8		)
Proved Developed Reserves - Revisions Other Than Price (MMBoe)	(28.3		)
Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) (k)	416.4
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k)	$	13.78

EOG RESOURCES, INC. Quantitative Reconciliation of Total Exploration and Development Expenditures For Drilling Only (Non-GAAP) and 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 data)
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and 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 “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or 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.
	2018			2017			2016			2015			2014
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	6,419.7		$	4,439.4		$	6,445.2		$	4,928.3		$	7,904.8
Less: Asset Retirement Costs	(69.7		)	(55.6		)	19.9			(53.5		)	(195.6		)
Non-Cash Acquisition Costs of Unproved Properties	(290.5		)	(255.7		)	(3,101.8		)	—			—
Acquisition Costs of Proved Properties	(123.7		)	(72.6		)	(749.0		)	(480.6		)	(139.1		)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) (a)	$	5,935.8		$	4,055.5		$	2,614.3		$	4,394.2		$	7,570.1
Total Costs Incurred in Exploration and Development Activities (GAAP)	$	6,419.7		$	4,439.4		$	6,445.2		$	4,928.3		$	7,904.8
Less: Asset Retirement Costs	(69.7		)	(55.6		)	19.9			(53.5		)	(195.6		)
Non-Cash Acquisition Costs of Unproved Properties	(290.5		)	(255.7		)	(3,101.8		)	—			—
Non-Cash Acquisition Costs of Proved Properties	(70.9		)	(26.2		)	(732.3		)	—			—
Total Exploration and Development Expenditures (Non-GAAP) (b)	$	5,988.6		$	4,101.9		$	2,631.0		$	4,874.8		$	7,709.2
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price (b)	34.8			154.0			(100.7		)	(573.8		)	52.2
Revisions Other Than Price	(39.5		)	48.0			252.9			107.2			48.4
Purchases in Place	11.6			2.3			42.3			56.2			14.4
Extensions, Discoveries and Other Additions (d)	669.7			420.8			209.0			245.9			519.2
Total Proved Reserve Additions (e)	676.6			625.1			403.5			(164.5		)	634.2
Sales in Place	(10.8		)	(20.7		)	(167.6		)	(3.5		)	(36.3		)
Net Proved Reserve Additions From All Sources (f)	665.8			604.4			235.9			(168.0		)	597.9
Production (g)	265.0			224.4			207.1			211.2			219.1
RESERVE REPLACEMENT COSTS ($ / Boe)
Total Drilling, Before Revisions (a / d)	$	8.86		$	9.64		$	12.51		$	17.87		$	14.58
All-in Total, Net of Revisions (b / e)	$	8.85		$	6.56		$	6.52		$	(29.63	)	$	12.16
All-in Total, Excluding Revisions Due to Price (b / ( e - c))	$	9.33		$	8.71		$	5.22		$	11.91		$	13.25

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 19, 2019. 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 December 31, 2018 (closed)	15,000	$	1.063
2019
January 1, 2019 through February 28, 2019 (closed)	20,000	$	1.075
March 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 through February 19, 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 December 31, 2018 (closed)	52,000	3.911
2019
January 1, 2019 through February 28, 2019 (closed)	13,000	$	5.572
March 1, 2019 through December 31, 2019	13,000	5.572

Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 19, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2018
January 1, 2018 through November 30, 2018 (closed)	134,000	$	60.04
On November 20, 2018, EOG entered into crude oil price swap contracts for the period December 1, 2018 through December 31, 2018, with notional volumes of 134,000 Bbld at an average price of $53.75 per Bbl. These contracts offset the crude oil price swap contracts for the same time period with notional volumes of 134,000 Bbld at an average price of $60.04 per Bbl. The net cash EOG received for settling these contracts was $26.1 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 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2018
March 1, 2018 through November 30, 2018 (closed)	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 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
Natural Gas Option Contracts
	Call Options Sold			Put Options Purchased
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)		Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2018
March 1, 2018 through November 30, 2018 (closed)	120,000	$	3.38	96,000	$	2.94

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 (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 (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 (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (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, 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.
	2018				2017
Return on Capital Employed (ROCE) (Non-GAAP)
Net Interest Expense (GAAP)	$	245
Tax Benefit Imputed (based on 21%)	(51		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	194
Net Income (GAAP) - (b)	$	3,419
Adjustments to Net Income, Net of Tax (See Accompanying Schedule)	(201		)	(1)
Adjusted Net Income (Non-GAAP) - (c)	$	3,218
Total Stockholders' Equity - (d)	$	19,364			$	16,283
Average Total Stockholders' Equity * - (e)	$	17,824
Current and Long-Term Debt (GAAP) - (f)	$	6,083			$	6,387
Less: Cash	(1,556		)		(834		)
Net Debt (Non-GAAP) - (g)	$	4,527			$	5,553
Total Capitalization (GAAP) - (d) + (f)	$	25,447			$	22,670
Total Capitalization (Non-GAAP) - (d) + (g)	$	23,891			$	21,836
Average Total Capitalization (Non-GAAP) * - (h)	$	22,864
ROCE (GAAP Net Income) - [(a) + (b)] / (h)	15.8		%
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h)	14.9		%
Return on Equity (ROE)
ROE (GAAP Net Income) - (b) / (e)	19.2		%
ROE (Non-GAAP Adjusted Net Income) - (c) / (e)	18.1		%
* Average for the current and immediately preceding year

Adjustments to Net Income (GAAP)

(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018:
		Year Ended December 31, 2018
		Before Tax			Income Tax Impact			After Tax
Adjustments:
Add:	Mark-to-Market Commodity Derivative Contracts Impact	$	(93	)	$	20		$	(73	)
Add:	Impairments of Certain Assets	153			(34		)	119
Less:	Net Gains on Asset Dispositions	(175		)	38			(137		)
Less:	Tax Reform Impact	—			(110		)	(110		)
Total		$	(115	)	$	(86	)	$	(201	)

EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. 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) (Calculated Using GAAP Net Income)
Net Interest Expense (GAAP)	$	274		$	282		$	237		$	201		$	235
Tax Benefit Imputed (based on 35%)	(96		)	(99		)	(83		)	(70		)	(82		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	178		$	183		$	154		$	131		$	153
Net Income (Loss) (GAAP) - (b)	$	2,583		$	(1,097	)	$	(4,525	)	$	2,915		$	2,197
Total Stockholders' Equity - (d)	$	16,283		$	13,982		$	12,943		$	17,713		$	15,418
Average Total Stockholders' Equity* - (e)	$	15,133		$	13,463		$	15,328		$	16,566		$	14,352
Current and Long-Term Debt (GAAP) - (f)	$	6,387		$	6,986		$	6,655		$	5,906		$	5,909
Less: Cash	(834		)	(1,600		)	(719		)	(2,087		)	(1,318		)
Net Debt (Non-GAAP) - (g)	$	5,553		$	5,386		$	5,936		$	3,819		$	4,591
Total Capitalization (GAAP) - (d) + (f)	$	22,670		$	20,968		$	19,598		$	23,619		$	21,327
Total Capitalization (Non-GAAP) - (d) + (g)	$	21,836		$	19,368		$	18,879		$	21,532		$	20,009
Average Total Capitalization (Non-GAAP)* - (h)	$	20,602		$	19,124		$	20,206		$	20,771		$	19,365
ROCE (GAAP Net Income) - [(a) + (b)] / (h)	13.4		%	-4.8		%	-21.6		%	14.7		%	12.1		%
Return on Equity (ROE) (GAAP)
ROE (GAAP Net Income) - (b) / (e)	17.1		%	-8.1		%	-29.5		%	17.6		%	15.3		%
* Average for the current and immediately preceding year

EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
	2012			2011			2010			2009			2008
Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)
Net Interest Expense (GAAP)	$	214		$	210		$	130		$	101		$	52
Tax Benefit Imputed (based on 35%)	(75		)	(74		)	(46		)	(35		)	(18		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	139		$	136		$	84		$	66		$	34
Net Income (Loss) (GAAP) - (b)	$	250		$	1,091		$	161		$	547		$	2,437
Total Stockholders' Equity - (d)	$	13,285		$	12,641		$	10,232		$	9,998		$	9,015
Average Total Stockholders' Equity* - (e)	$	12,963		$	11,437		$	10,115		$	9,507		$	8,003
Current and Long-Term Debt (GAAP) - (f)	$	6,312		$	5,009		$	5,223		$	2,797		$	1,897
Less: Cash	(876		)	(616		)	(789		)	(686		)	(331		)
Net Debt (Non-GAAP) - (g)	$	5,436		$	4,393		$	4,434		$	2,111		$	1,566
Total Capitalization (GAAP) - (d) + (f)	$	19,597		$	17,650		$	15,455		$	12,795		$	10,912
Total Capitalization (Non-GAAP) - (d) + (g)	$	18,721		$	17,034		$	14,666		$	12,109		$	10,581
Average Total Capitalization (Non-GAAP)* - (h)	$	17,878		$	15,850		$	13,388		$	11,345		$	9,351
ROCE (GAAP Net Income) - [(a) + (b)] / (h)	4.0		%	7.7		%	1.8		%	5.4		%	26.4		%
Return on Equity (ROE) (GAAP)
ROE (GAAP Net Income) - (b) / (e)	4.4		%	9.5		%	1.6		%	5.8		%	30.5		%
* Average for the current and immediately preceding year

EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
	2007			2006			2005			2004			2003
Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)
Net Interest Expense (GAAP)	$	47		$	43		$	63		$	63		$	59
Tax Benefit Imputed (based on 35%)	(16		)	(15		)	(22		)	(22		)	(21		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	31		$	28		$	41		$	41		$	38
Net Income (Loss) (GAAP) - (b)	$	1,090		$	1,300		$	1,260		$	625		$	430
Total Stockholders' Equity - (d)	$	6,990		$	5,600		$	4,316		$	2,945		$	2,223
Average Total Stockholders' Equity* - (e)	$	6,295		$	4,958		$	3,631		$	2,584		$	1,948
Current and Long-Term Debt (GAAP) - (f)	$	1,185		$	733		$	985		$	1,078		$	1,109
Less: Cash	(54		)	(218		)	(644		)	(21		)	(4		)
Net Debt (Non-GAAP) - (g)	$	1,131		$	515		$	341		$	1,057		$	1,105
Total Capitalization (GAAP) - (d) + (f)	$	8,175		$	6,333		$	5,301		$	4,023		$	3,332
Total Capitalization (Non-GAAP) - (d) + (g)	$	8,121		$	6,115		$	4,657		$	4,002		$	3,328
Average Total Capitalization (Non-GAAP)* - (h)	$	7,118		$	5,386		$	4,330		$	3,665		$	3,068
ROCE (GAAP Net Income) - [(a) + (b)] / (h)	15.7		%	24.7		%	30.0		%	18.2		%	15.3		%
Return on Equity (ROE) (GAAP)
ROE (GAAP Net Income) - (b) / (e)	17.3		%	26.2		%	34.7		%	24.2		%	22.1		%
* Average for the current and immediately preceding year

EOG RESOURCES, INC. Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest Expense (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), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
	2002			2001			2000			1999			1998
Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)
Net Interest Expense (GAAP)	$	60		$	45		$	61		$	62
Tax Benefit Imputed (based on 35%)	(21		)	(16		)	(21		)	(22		)
After-Tax Net Interest Expense (Non-GAAP) - (a)	$	39		$	29		$	40		$	40
Net Income (Loss) (GAAP) - (b)	$	87		$	399		$	397		$	569
Total Stockholders' Equity - (d)	$	1,672		$	1,643		$	1,381		$	1,130		$	1,280
Average Total Stockholders' Equity* - (e)	$	1,658		$	1,512		$	1,256		$	1,205
Current and Long-Term Debt (GAAP) - (f)	$	1,145		$	856		$	859		$	990		$	1,143
Less: Cash	(10		)	(3		)	(20		)	(25		)	(6		)
Net Debt (Non-GAAP) - (g)	$	1,135		$	853		$	839		$	965		$	1,137
Total Capitalization (GAAP) - (d) + (f)	$	2,817		$	2,499		$	2,240		$	2,120		$	2,423
Total Capitalization (Non-GAAP) - (d) + (g)	$	2,807		$	2,496		$	2,220		$	2,095		$	2,417
Average Total Capitalization (Non-GAAP)* - (h)	$	2,652		$	2,358		$	2,158		$	2,256
ROCE (GAAP Net Income) - [(a) + (b)] / (h)	4.8		%	18.2		%	20.2		%	27.0		%
Return on Equity (ROE) (GAAP)
ROE (GAAP Net Income) - (b) / (e)	5.2		%	26.4		%	31.6		%	47.2		%
* Average for the current and immediately preceding year

EOG RESOURCES, INC. Cash Operating Expenses per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)
	Year Ended December 31,
	2018				2017				2016				2015				2014
Cash Operating Expenses (GAAP)*
Lease and Well	$	1,282,678			$	1,044,847			$	927,452			$	1,182,282			$	1,416,413
Transportation Costs	746,876				740,352				764,106				849,319				972,176
General and Administrative	426,969				434,467				394,815				366,594				402,010
Cash Operating Expense	2,456,523				2,219,666				2,086,373				2,398,195				2,790,599
Less: Legal Settlement - Early Leasehold Termination	—				(10,202		)		—				(19,355		)		—
Less: Voluntary Retirement Expense	—				—				(42,054		)		—				—
Less: Acquisition Costs - Yates Transaction	—				—				(5,100		)		—				—
Less: Joint Venture Transaction Costs	—				(3,056		)		—				—				—
Less: Joint Interest Billings Deemed Uncollectible	—				(4,528		)		—				—				—
Adjusted Cash Operating Expenses (Non-GAAP) - (a)	$	2,456,523			$	2,201,880			$	2,039,219			$	2,378,840			$	2,790,599
Volume - Thousand Barrels of Oil Equivalent - (b)	262,516				222,251				204,929				208,862				217,073
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b)	$	9.36		(c)	$	9.91		(d)	$	9.95		(e)	$	11.39		(f)	$	12.86	(g)
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - Percentage Decrease
2018 compared to 2017 - [(c) - (d)] / (d)	-6		%
2018 compared to 2016 - [(c) - (e)] / (e)	-6		%
2018 compared to 2015 - [(c) - (f)] / (f)	-18		%
2018 compared to 2014 - [(c) - (g)] / (g)	-27		%
*Includes stock compensation expense and other non-cash items.

EOG RESOURCES, INC. Cost per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)
	Three Months Ended
	March 31,			June 30,		September 30,		December 31,
	2018			2018		2018		2018
Volume - Thousand Barrels of Oil Equivalent - (a)	59,394			63,898		68,890		70,334
Crude Oil and Condensate	$	2,101,308		$	2,377,528	$	2,655,278	$	2,383,326
Natural Gas Liquids	221,415			286,354		353,704		266,037
Natural Gas	299,766			300,845		311,713		389,213
Total Wellhead Revenues - (b)	$	2,622,489		$	2,964,727	$	3,320,695	$	3,038,576
Operating Costs
Lease and Well	$	300,064		$	314,604	$	321,568	$	346,442
Transportation Costs	176,957			177,797		196,027		196,095
Gathering and Processing Costs	101,345			109,169		114,063		112,396
General and Administrative	94,698			104,083		111,284		116,904
Taxes Other Than Income	179,084			194,268		209,043		190,086
Interest Expense, Net	61,956			63,444		63,632		56,020
Total Cash Operating Cost (excluding DD&A and Exploration Costs) - (c)	$	914,104		$	963,365	$	1,015,617	$	1,017,943
Depreciation, Depletion and Amortization (DD&A)	748,591			848,674		918,180		919,963
Total Operating Cost (excluding Exploration Costs) - (d)	$	1,662,695		$	1,812,039	$	1,933,797	$	1,937,906
Exploration Costs	$	34,836		$	47,478	$	32,823	$	33,862
Dry Hole Costs	—			4,902		358		145
Impairments	64,609			51,708		44,617		186,087
Total Exploration Costs	99,445			104,088		77,798		220,094
Less: Impairments (Non-GAAP)	(20,876		)	—		—		(131,795		)
Total Exploration Costs (Non-GAAP)	$	78,569		$	104,088	$	77,798	$	88,299
Total Operating Cost (Non-GAAP) (including Exploration Costs) - (e)	$	1,741,264		$	1,916,127	$	2,011,595	$	2,026,205
Composite Average Wellhead Revenue per Boe - (b) / (a)	$	44.15		$	46.40	$	48.20	$	43.20
Total Cash Operating Cost per Boe (excluding DD&A and Exploration Costs) - (c) / (a)	$	15.39		$	15.07	$	14.75	$	14.48
Composite Average Margin per Boe (excluding DD&A and Exploration Costs) - [(b) / (a) - (c) / (a)]	$	28.76		$	31.33	$	33.45	$	28.72
Total Operating Cost per Boe (excluding Exploration Costs) - (d) / (a)	$	27.99		$	28.35	$	28.08	$	27.56
Composite Average Margin per Boe (excluding Exploration Costs) - [(b) / (a) - (d) / (a)]	$	16.16		$	18.05	$	20.12	$	15.64
Total Operating Cost per Boe (Non-GAAP) (including Exploration Costs) - (e) / (a)	$	29.31		$	29.98	$	29.21	$	28.82
Composite Average Margin per Boe (Non-GAAP) (including Exploration Costs) - [(b) / (a) - (e) / (a)]	$	14.84		$	16.42	$	18.99	$	14.38

EOG RESOURCES, INC. Cost per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)
	Year Ended December 31,
	2018			2017			2016			2015			2014
Volume - Thousand Barrels of Oil Equivalent (a)	262,516			222,251			204,929			208,862			217,073
Crude Oil and Condensate	$	9,517,440		$	6,256,396		$	4,317,341		$	4,934,562		$	9,742,480
Natural Gas Liquids	1,127,510			729,561			437,250			407,658			934,051
Natural Gas	1,301,537			921,934			742,152			1,061,038			1,916,386
Total Wellhead Revenues - (b)	$	11,946,487		$	7,907,891		$	5,496,743		$	6,403,258		$	12,592,917
Operating Costs
Lease and Well	$	1,282,678		$	1,044,847		$	927,452		$	1,182,282		$	1,416,413
Transportation Costs	746,876			740,352			764,106			849,319			972,176
Gathering and Processing Costs	436,973			148,775			122,901			146,156			145,800
General and Administrative	426,969			434,467			394,815			366,594			402,010
Less: Voluntary Retirement Expense	—			—			(42,054		)	—			—
Less: Acquisition Costs	—			—			(5,100		)	—			—
Less: Legal Settlement - Early Leasehold Termination	—			(10,202		)	—			(19,355		)	—
Less: Joint Venture Transaction Costs	—			(3,056		)	—			—			—
Less: Joint Interest Billings Deemed Uncollectible	—			(4,528		)	—			—			—
General and Administrative (Non-GAAP)	426,969			416,681			347,661			347,239			402,010
Taxes Other Than Income	772,481			544,662			349,710			421,744			757,564
Interest Expense, Net	245,052			274,372			281,681			237,393			201,458
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Exploration Costs) - (c)	$	3,911,029		$	3,169,689		$	2,793,511		$	3,184,133		$	3,895,421
Depreciation, Depletion and Amortization (DD&A)	3,435,408			3,409,387			3,553,417			3,313,644			3,997,041
Total Operating Cost (Non-GAAP) (excluding Exploration Costs) - (d)	$	7,346,437		$	6,579,076		$	6,346,928		$	6,497,777		$	7,892,462
Exploration Costs	$	148,999		$	145,342		$	124,953		$	149,494		$	184,388
Dry Hole Costs	5,405			4,609			10,657			14,746			48,490
Impairments	347,021			479,240			620,267			6,613,546			743,575
Total Exploration Costs	501,425			629,191			755,877			6,777,786			976,453
Less: Impairments (Non-GAAP)	(152,671		)	(261,452		)	(320,617		)	(6,307,593		)	(824,312		)
Total Exploration Costs (Non-GAAP)	$	348,754		$	367,739		$	435,260		$	470,193		$	152,141
Total Operating Cost (Non-GAAP) (including Exploration Costs) - (e)	$	7,695,191		$	6,946,815		$	6,782,188		$	6,967,970		$	8,044,603

EOG RESOURCES, INC. Cost per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)
	Year Ended December 31,
	2018		2017		2016			2015			2014
Composite Average Wellhead Revenue per Boe - (b) / (a)	$	45.51	$	35.58	$	26.82		$	30.66		$	58.01
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Exploration Costs) - (c) / (a)	$	14.90	$	14.25	$	13.64		$	15.25		$	17.95
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Exploration Costs) - [(b) / (a) - (c) / (a)]	$	30.61	$	21.33	$	13.18		$	15.41		$	40.06
Total Operating Cost per Boe (Non-GAAP) (excluding Exploration Costs) - (d) / (a)	$	27.99	$	29.59	$	30.98		$	31.11		$	36.38
Composite Average Margin per Boe (Non-GAAP) (excluding Exploration Costs) - [(b) / (a) - (d) / (a)]	$	17.52	$	5.99	$	(4.16	)	$	(0.45	)	$	21.63
Total Operating Cost per Boe (Non-GAAP) (including Exploration Costs) - (e) / (a)	$	29.32	$	31.24	$	33.10		$	33.36		$	37.08
Composite Average Margin per Boe (Non-GAAP) (including Exploration Costs) - [(b) / (a) - (e) / (a)]	$	16.19	$	4.34	$	(6.28	)	$	(2.70	)	$	20.93

EOG RESOURCES, INC. First Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing
(a) First Quarter and Full Year 2019 Forecast
The forecast items for the first quarter and full year 2019 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) Capital Expenditures
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges.
(c) 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 2019					Full Year 2019
Daily Sales Volumes
Crude Oil and Condensate Volumes (MBbld)
United States		426.6	-		434.2		442.6	-		458.2
Trinidad		0.4	-		0.6		0.4	-		0.6
Other International		0.0	-		0.2		0.0	-		0.2
Total		427.0	-		435.0		443.0	-		459.0
Natural Gas Liquids Volumes (MBbld)
Total		115.0	-		125.0		120.0	-		140.0
Natural Gas Volumes (MMcfd)
United States		950	-		1,000		1,030	-		1,130
Trinidad		245	-		275		250	-		290
Other International		30	-		40		30	-		40
Total		1,225	-		1,315		1,310	-		1,460
Crude Oil Equivalent Volumes (MBoed)
United States		699.9	-		725.9		734.3	-		786.5
Trinidad		41.2	-		46.4		42.1	-		48.9
Other International		5.0	-		6.9		5.0	-		6.9
Total		746.1	-		779.2		781.4	-		842.3
Capital Expenditures ($MM)	$	1,750		$	1,950	$	6,100		$	6,500

		Estimated Ranges (Unaudited)
		1Q 2019							Full Year 2019
Operating Costs
Unit Costs ($/Boe)
Lease and Well		$	4.90		-	$	5.30		$	4.50		-	$	5.30
Transportation Costs		$	2.50		-	$	3.00		$	2.60		-	$	3.10
Depreciation, Depletion and Amortization		$	12.50		-	$	13.00		$	12.25		-	$	13.25
Expenses ($MM)
Exploration and Dry Hole		$	35		-	$	45		$	155		-	$	195
Impairment		$	55			$	65		$	190			$	230
General and Administrative		$	110		-	$	120		$	450		-	$	490
Gathering and Processing		$	100		-	$	110		$	440		-	$	480
Capitalized Interest		$	6		-	$	8		$	25		-	$	30
Net Interest		$	54		-	$	56		$	190		-	$	200
Taxes Other Than Income (% of Wellhead Revenue)			7.2	%	-		7.6	%		7.2	%	-		7.6	%
Income Taxes
Effective Rate			20	%	-		25	%		20	%	-		25	%
Current Tax (Benefit) / Expense ($MM)		$	(55	)	-	$	(15	)	$	(190	)	-	$	(110	)
Pricing - (Refer to Benchmark Commodity Pricing in text)
Crude Oil and Condensate ($/Bbl)
Differentials
United States - above (below) WTI		$	0.25		-	$	1.25		$	(1.00	)	-	$	1.00
Trinidad - above (below) WTI		$	(11.00	)	-	$	(9.00	)	$	(11.00	)	-	$	(9.00	)
Other International - above (below) WTI		$	5.00		-	$	9.00		$	(1.00	)	-	$	1.00
Natural Gas Liquids
Realizations as % of WTI			37	%	-		43	%		37	%	-		43	%
Natural Gas ($/Mcf)
Differentials
United States - above (below) NYMEX Henry Hub		$	(0.40	)	-	$	0.00		$	(0.50	)	-	$	0.10
Realizations
Trinidad		$	2.50		-	$	2.90		$	2.50		-	$	3.20
Other International		$	4.30		-	$	4.80		$	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