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

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

March 1, 2019

  • 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

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 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

Income

Diluted

Income

Diluted

Before

Tax

After

Earnings

Before

Tax

After

Earnings

Tax

Impact

Tax

per Share

Tax

Impact

Tax

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

Income

Diluted

Income

Diluted

Before

Tax

After

Earnings

Before

Tax

After

Earnings

Tax

Impact

Tax

per Share

Tax

Impact

Tax

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 

 Other 

 States 

Trinidad

 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 

 Other 

 States 

Trinidad

 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 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.

For the Twelve Months Ended December 31, 2018

 United 

 Other 

 States 

 Trinidad 

 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%

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

 Total 

PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)

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 (c)

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

Weighted

Average Price

Volume

Differential

(Bbld) 

($/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

Weighted

Average Price

Volume

Differential

(Bbld) 

($/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

Weighted

Volume

Average Price

(Bbld) 

($/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

Weighted

Volume

Average Price

(MMBtud)

($/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

Weighted

Weighted

Volume

Average Price

Volume

Average Price

(MMBtud) 

($/MMBtu) 

(MMBtud)

($/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 

 Income Tax  

 After 

 Tax 

 Impact 

 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)                                                   

$

570

$

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 Expenses

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

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 toBenchmark Commodity Pricingin 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

SOURCE EOG Resources, Inc.

https://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2018-results-and-announces-2019-capital-program-300802665.html

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