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

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HOUSTON, Feb. 27, 2018 /PRNewswire/ --

  • Delivers 20 Percent U.S. Crude Oil Production Growth and Pays Dividend within Cash Flow
  • Lowers Per-Unit Transportation and DD&A Expenses Below Targets
  • Increases Proved Reserves 18 Percent and Replaces 201 Percent of 2017 Production at Low Finding Costs
  • Raises Common Stock Dividend 10 Percent
  • Targets 18 Percent Crude Oil Production Growth and 16 Percent Total Production Growth for 2018 with Significant Free Cash Flow at $60 Oil
  • Expects to Earn Double-Digit ROCE in 2018

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

In the fourth quarter, EOG completed nine wells in the Powder River Basin.  In Converse County, EOG completed the Mary's Draw 453-0310H and 455-0310H wells with an average treated lateral length of 7,300 feet per well and average 30-day initial production rates per well of 1,280 Bopd, 610 Bpd of NGLs and 7.6 MMcfd of natural gas.  In the DJ Basin, EOG completed three wells in the fourth quarter.  This included the Big Sandy 522-2536H with a treated lateral length of 8,800 feet and 30-day initial production rate of 1,100 Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.

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

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

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

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

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

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

EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China.  EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."  For additional information about EOG, please visit www.eogresources.com.

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

  • the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
  • the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
  • the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
  • the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
  • the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
  • the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;
  • the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
  • the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;
  • competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
  • the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
  • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
  • weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
  • the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
  • EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
  • the extent to which EOG is successful in its completion of planned asset dispositions;
  • the extent and effect of any hedging activities engaged in by EOG;
  • the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
  • political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
  • the use of competing energy sources and the development of alternative energy sources;
  • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
  • acts of war and terrorism and responses to these acts;
  • physical, electronic and cyber security breaches; and
  • the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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

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

For Further Information Contact:

Investors

 

David J. Streit

 

(713) 571-4902

 

Neel Panchal

 

(713) 571-4884

 

W. John Wagner

 

(713) 571-4404

   
 

Media and Investors

 

Kimberly M. Ehmer

 

(713) 571-4676

 

EOG RESOURCES, INC.

Financial Report

(Unaudited; in millions, except per share data)

                       
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

                       

Net Operating Revenues and Other

$

3,340.4

 

$

2,402.0

 

$

11,208.3

 

$

7,650.6

Net Income (Loss)

$

2,430.5

 

$

(142.4)

 

$

2,582.6

 

$

(1,096.7)

Net Income (Loss) Per Share 

                     

        Basic

$

4.22

 

$

(0.25)

 

$

4.49

 

$

(1.98)

        Diluted

$

4.20

 

$

(0.25)

 

$

4.46

 

$

(1.98)

Average Number of Common Shares

                     

        Basic

 

575.4

   

567.3

   

574.6

   

553.4

        Diluted

 

579.2

   

567.3

   

578.7

   

553.4

                       
                       

Summary Income Statements

(Unaudited; in thousands, except per share data)

                       
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

Net Operating Revenues and Other

             

        Crude Oil and Condensate

$

1,929,471

 

$

1,366,223

 

$

6,256,396

 

$

4,317,341

        Natural Gas Liquids

 

249,172

   

137,849

   

729,561

   

437,250

        Natural Gas

 

246,922

   

215,373

   

921,934

   

742,152

        Gains (Losses) on Mark-to-Market Commodity Derivative Contracts

 

(45,032)

   

(65,787)

   

19,828

   

(99,608)

        Gathering, Processing and Marketing

 

1,008,385

   

614,594

   

3,298,087

   

1,966,259

        Gains (Losses) on Asset Dispositions, Net

 

(65,220)

   

104,034

   

(99,096)

   

205,835

        Other, Net

 

16,741

   

29,753

   

81,610

   

81,403

               Total

 

3,340,439

   

2,402,039

   

11,208,320

   

7,650,632

Operating Expenses

                     

        Lease and Well

 

281,941

   

241,846

   

1,044,847

   

927,452

        Transportation Costs

 

191,717

   

193,319

   

740,352

   

764,106

        Gathering and Processing Costs

 

43,295

   

32,516

   

148,775

   

122,901

        Exploration Costs

 

22,941

   

39,110

   

145,342

   

124,953

        Dry Hole Costs

 

4,532

   

193

   

4,609

   

10,657

        Impairments 

 

153,442

   

297,946

   

479,240

   

620,267

        Marketing Costs

 

1,009,566

   

634,248

   

3,330,237

   

2,007,635

        Depreciation, Depletion and Amortization

 

881,745

   

862,524

   

3,409,387

   

3,553,417

        General and Administrative

 

117,005

   

102,182

   

434,467

   

394,815

        Taxes Other Than Income

 

158,343

   

103,642

   

544,662

   

349,710

               Total

 

2,864,527

   

2,507,526

   

10,281,918

   

8,875,913

                       

Operating Income (Loss)

 

475,912

   

(105,487)

   

926,402

   

(1,225,281)

                       

Other Income (Expense), Net

 

803

   

(17,198)

   

9,152

   

(50,543)

                       

Income (Loss) Before Interest Expense and Income Taxes

476,715

   

(122,685)

   

935,554

   

(1,275,824)

                       

Interest Expense, Net

 

63,362

   

71,325

   

274,372

   

281,681

                       

Income (Loss) Before Income Taxes

 

413,353

   

(194,010)

   

661,182

   

(1,557,505)

                       

Income Tax Benefit

 

(2,017,115)

   

(51,658)

   

(1,921,397)

   

(460,819)

                       

Net Income (Loss)

$

2,430,468

 

$

(142,352)

 

$

2,582,579

 

$

(1,096,686)

                       

Dividends Declared per Common Share

$

0.1675

 

$

0.1675

 

$

0.6700

 

$

0.6700

 

 
 

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)

                       
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

Wellhead Volumes and Prices

     

Crude Oil and Condensate Volumes (MBbld) (A)

     

      United States

 

366.9

   

306.0

   

335.0

   

278.3

      Trinidad

 

1.1

   

0.9

   

0.9

   

0.8

      Other International (B)

 

0.1

   

4.8

   

0.8

   

3.4

            Total

 

368.1

   

311.7

   

336.7

   

282.5

                       

Average Crude Oil and Condensate Prices ($/Bbl) (C)

                     

      United States

$

56.95

 

$

47.93

 

$

50.91

 

$

41.84

      Trinidad

 

46.56

   

40.04

   

42.30

   

33.76

      Other International (B)

 

45.72

   

38.96

   

57.20

   

36.72

            Composite

 

56.97

   

47.76

   

50.91

   

41.76

                       

Natural Gas Liquids Volumes (MBbld) (A)

                     

      United States

 

100.6

   

80.9

   

88.4

   

81.6

      Other International (B)

 

-

   

-

   

-

   

-

            Total

 

100.6

   

80.9

   

88.4

   

81.6

                       

Average Natural Gas Liquids Prices ($/Bbl) (C)

                     

      United States

$

26.92

 

$

18.51

 

$

22.61

 

$

14.63

      Other International (B)

 

-

   

-

   

-

   

-

            Composite

 

26.92

   

18.51

   

22.61

   

14.63

                       

Natural Gas Volumes (MMcfd) (A)

                     

      United States

 

829

   

800

   

765

   

810

      Trinidad

 

299

   

323

   

313

   

340

      Other International (B)

 

32

   

22

   

25

   

25

            Total

 

1,160

   

1,145

   

1,103

   

1,175

                       

Average Natural Gas Prices ($/Mcf) (C)

                     

      United States

$

2.17

 

$

2.05

 

$

2.20

 

$

1.60

      Trinidad

 

2.52

   

1.89

   

2.38

   

1.88

      Other International (B)

 

4.23

   

3.85

   

3.89

   

3.64

            Composite

 

2.31

   

2.04

   

2.29

   

1.73

                       

Crude Oil Equivalent Volumes (MBoed) (D)

                     

      United States 

 

605.6

   

520.3

   

551.0

   

494.9

      Trinidad

 

51.0

   

54.6

   

53.0

   

57.5

      Other International (B)

 

5.4

   

8.6

   

4.9

   

7.6

            Total

 

662.0

   

583.5

   

608.9

   

560.0

                       

Total MMBoe (D)

 

60.9

   

53.7

   

222.3

   

205.0

                       

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

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

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

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

 

 
 

EOG RESOURCES, INC.

Summary Balance Sheets

(Unaudited; in thousands, except share data)

           
 

December 31,

 

December 31,

 

2017

 

2016

ASSETS

Current Assets

         

     Cash and Cash Equivalents

$

834,228

 

$

1,599,895

     Accounts Receivable, Net

 

1,597,494

   

1,216,320

     Inventories

 

483,865

   

350,017

     Assets from Price Risk Management Activities

 

7,699

   

-

     Income Taxes Receivable

 

113,357

   

12,305

     Other

 

242,465

   

206,679

            Total

 

3,279,108

   

3,385,216

           

Property, Plant and Equipment

         

     Oil and Gas Properties (Successful Efforts Method)

 

52,555,741

   

49,592,091

     Other Property, Plant and Equipment

 

3,960,759

   

4,008,564

            Total Property, Plant and Equipment

 

56,516,500

   

53,600,655

     Less:  Accumulated Depreciation, Depletion and Amortization

 

(30,851,463)

   

(27,893,577)

            Total Property, Plant and Equipment, Net

 

25,665,037

   

25,707,078

Deferred Income Taxes

 

17,506

   

16,140

Other Assets

 

871,427

   

190,767

Total Assets

$

29,833,078

 

$

29,299,201

           

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         

     Accounts Payable

$

1,847,131

 

$

1,511,826

     Accrued Taxes Payable

 

148,874

   

118,411

     Dividends Payable

 

96,410

   

96,120

     Liabilities from Price Risk Management Activities

 

50,429

   

61,817

     Current Portion of Long-Term Debt

 

356,235

   

6,579

     Other

 

226,463

   

232,538

            Total

 

2,725,542

   

2,027,291

           
           

Long-Term Debt

 

6,030,836

   

6,979,779

Other Liabilities

 

1,275,213

   

1,282,142

Deferred Income Taxes

 

3,518,214

   

5,028,408

Commitments and Contingencies

         
           

Stockholders' Equity

         

     Common Stock, $0.01 Par, 1,280,000,000 Shares and 640,000,000
        Shares Authorized at December 31, 2017 and 2016, respectively, and
        578,827,768 Shares and 576,950,272 Shares Issued at
        December 31, 2017 and 2016, respectively 

 

205,788

   

205,770

     Additional Paid in Capital

 

5,536,547

   

5,420,385

     Accumulated Other Comprehensive Loss

 

(19,297)

   

(19,010)

     Retained Earnings

 

10,593,533

   

8,398,118

     Common Stock Held in Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017 and 2016, respectively

 

(33,298)

   

(23,682)

            Total Stockholders' Equity

 

16,283,273

   

13,981,581

Total Liabilities and Stockholders' Equity

$

29,833,078

 

$

29,299,201

 

 
 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

           
 

Twelve Months Ended

 

December 31,

 

2017

 

2016

Cash Flows from Operating Activities

         

Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:

         

     Net Income (Loss)

$

2,582,579

   

(1,096,686)

     Items Not Requiring (Providing) Cash

         

            Depreciation, Depletion and Amortization

 

3,409,387

   

3,553,417

            Impairments 

 

479,240

   

620,267

            Stock-Based Compensation Expenses

 

133,849

   

128,090

            Deferred Income Taxes

 

(1,473,872)

   

(515,206)

            (Gains) Losses on Asset Dispositions, Net

 

99,096

   

(205,835)

            Other, Net

 

6,546

   

61,690

     Dry Hole Costs

 

4,609

   

10,657

     Mark-to-Market Commodity Derivative Contracts

         

            Total (Gains) Losses

 

(19,828)

   

99,608

            Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 

 

7,438

   

(22,219)

     Excess Tax Benefits from Stock-Based Compensation

 

-

   

(29,357)

     Other, Net

 

1,204

   

10,971

     Changes in Components of Working Capital and Other Assets and Liabilities

         

            Accounts Receivable

 

(392,131)

   

(232,799)

            Inventories

 

(174,548)

   

170,694

            Accounts Payable

 

324,192

   

(74,048)

            Accrued Taxes Payable

 

(63,937)

   

92,782

            Other Assets

 

(658,609)

   

(40,636)

            Other Liabilities

 

(89,871)

   

(16,225)

     Changes in Components of Working Capital Associated with Investing and Financing Activities

 

89,992

   

(156,102)

Net Cash Provided by Operating Activities

 

4,265,336

   

2,359,063

           

Investing Cash Flows

         

     Additions to Oil and Gas Properties

 

(3,950,918)

   

(2,489,756)

     Additions to Other Property, Plant and Equipment

 

(173,324)

   

(93,039)

     Proceeds from Sales of Assets

 

226,768

   

1,119,215

     Net Cash Received from Yates Transaction

 

-

   

54,534

     Changes in Components of Working Capital Associated with Investing Activities

 

(89,935)

   

156,102

Net Cash Used in Investing Activities

 

(3,987,409)

   

(1,252,944)

           

Financing Cash Flows

         

     Net Commercial Paper Repayments

 

-

   

(259,718)

     Long-Term Debt Borrowings

 

-

   

991,097

     Long-Term Debt Repayments

 

(600,000)

   

(563,829)

     Dividends Paid

 

(386,531)

   

(372,845)

     Excess Tax Benefits from Stock-Based Compensation

 

-

   

29,357

     Treasury Stock Purchased

 

(63,408)

   

(82,125)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

 

20,840

   

23,296

     Debt Issuance Costs

 

-

   

(1,602)

     Repayment of Capital Lease Obligation

 

(6,555)

   

(6,353)

     Other, Net

 

(57)

   

-

Net Cash Used in Financing Activities

 

(1,035,711)

   

(242,722)

           

Effect of Exchange Rate Changes on Cash

 

(7,883)

   

17,992

           

Increase (Decrease) in Cash and Cash Equivalents

 

(765,667)

   

881,389

Cash and Cash Equivalents at Beginning of Period

 

1,599,895

   

718,506

Cash and Cash Equivalents at End of Period

$

834,228

 

$

1,599,895

 

 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP)

To Net Income (Loss) (GAAP)

(Unaudited; in thousands, except per share data)

                               

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

                               
 

Three Months Ended 

 

Three Months Ended 

 

December 31, 2017

 

December 31, 2016

                               
     

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 (Loss) (GAAP)

$    413,353

 

$2,017,115

 

$ 2,430,468

 

$      4.20

 

$   (194,010)

 

$     51,658

 

$  (142,352)

 

$     (0.25)

Adjustments:

                             

(Gains) Losses on Mark-to-Market Commodity
     
Derivative Contracts

45,032

 

(16,142)

 

28,890

 

0.05

 

65,787

 

(23,583)

 

42,204

 

0.07

Net Cash Received from (Payments for)

     Settlements of Commodity Derivative
     Contracts

2,708

 

(971)

 

1,737

 

-

 

-

 

29

 

29

 

-

Add:  Net (Gains) Losses on Asset Dispositions

65,220

 

(23,315)

 

41,905

 

0.07

 

(104,034)

 

36,856

 

(67,178)

 

(0.12)

Add:  Impairments

100,304

 

(35,954)

 

64,350

 

0.11

 

217,839

 

(76,728)

 

141,111

 

0.25

Add:  Voluntary Retirement Expense

-

 

-

 

-

 

-

 

-

 

(57)

 

(57)

 

-

Add:  Acquisition - State Apportionment Change

-

 

-

 

-

 

-

 

-

 

16,424

 

16,424

 

0.03

Add:  Acquisition Costs

-

 

-

 

-

 

-

 

2,173

 

955

 

3,128

 

0.01

Add:  Joint Interest Billings Deemed Uncollectible

4,528

 

(1,623)

 

2,905

 

0.01

 

-

 

-

 

-

 

-

Less:  Tax Reform Impact

-

 

(2,169,376)

 

(2,169,376)

 

(3.75)

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

217,792

 

(2,247,381)

 

(2,029,589)

 

(3.51)

 

181,765

 

(46,104)

 

135,661

 

0.24

                               

Adjusted Net Income (Loss) (Non-GAAP)

$    631,145

 

$  (230,266)

 

$   400,879

 

$      0.69

 

$     (12,245)

 

$       5,554

 

$      (6,691)

 

$     (0.01)

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

575,394

             

567,337

       Diluted

           

579,203

             

567,337

                               
                               
 

Twelve Months Ended 

 

Twelve Months Ended 

 

December 31, 2017

 

December 31, 2016

                               
     

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 (Loss) (GAAP)

$    661,182

 

$1,921,397

 

$ 2,582,579

 

$      4.46

 

$(1,557,505)

 

$   460,819

 

$(1,096,686)

 

$     (1.98)

Adjustments:

                             

(Gains) Losses on Mark-to-Market Commodity
     Derivative Contracts

(19,828)

 

7,107

 

(12,721)

 

(0.02)

 

99,608

 

(35,640)

 

63,968

 

0.12

Net Cash Received from (Payments for)
     Settlements of Commodity Derivative 
     Contracts

7,438

 

(2,666)

 

4,772

 

0.01

 

(22,219)

 

7,950

 

(14,269)

 

(0.03)

Add:  Net (Gains) Losses on Asset Dispositions

99,096

 

(35,270)

 

63,826

 

0.11

 

(205,835)

 

61,491

 

(144,344)

 

(0.26)

Add:  Impairments

261,452

 

(93,718)

 

167,734

 

0.29

 

320,617

 

(113,368)

 

207,249

 

0.37

Add:  Trinidad Tax Settlement

-

 

-

 

-

 

-

 

-

 

43,000

 

43,000

 

0.08

Add:  Voluntary Retirement Expense

-

 

-

 

-

 

-

 

42,054

 

(15,047)

 

27,007

 

0.05

Add:  Acquisition - State Apportionment Change

-

 

-

 

-

 

-

 

-

 

16,424

 

16,424

 

0.03

Add:  Acquisition Costs

-

 

-

 

-

 

-

 

5,100

 

(88)

 

5,012

 

0.01

Add:  Legal Settlement - Early Lease Termination

10,202

 

(3,657)

 

6,545

 

0.01

 

-

 

-

 

-

 

-

Add:  Joint Venture Transaction Costs

3,056

 

(1,095)

 

1,961

 

-

 

-

 

-

 

-

 

-

Add:  Joint Interest Billings Deemed Uncollectible

4,528

 

(1,623)

 

2,905

 

0.01

 

-

 

-

 

-

 

-

Less:  Tax Reform Impact

-

 

(2,169,376)

 

(2,169,376)

 

(3.75)

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

365,944

 

(2,300,298)

 

(1,934,354)

 

(3.34)

 

239,325

 

(35,278)

 

204,047

 

0.37

                               

Adjusted Net Income (Loss) (Non-GAAP)

$ 1,027,126

 

$  (378,901)

 

$   648,225

 

$      1.12

 

$(1,318,180)

 

$   425,541

 

$  (892,639)

 

$     (1.61)

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

574,620

             

553,384

       Diluted

           

578,693

             

553,384

 

 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)

To Net Cash Provided By Operating Activities (GAAP)

(Unaudited; in thousands)

                         

Calculation of Free Cash Flow (Non-GAAP)

(Unaudited; in thousands)

 

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

                         
   

Three Months Ended

 

Twelve Months Ended

   

December 31,

 

December 31,

   

2017

 

2016

 

2017

 

2016

                         

Net Cash Provided by Operating Activities (GAAP)

$

1,327,548

 

$

804,745

 

$

4,265,336

 

$

2,359,063

                         

Adjustments:

                       

Exploration Costs (excluding Stock-Based Compensation Expenses) 

   

16,420

   

33,931

   

122,688

   

104,199

Excess Tax Benefits from Stock-Based Compensation

   

-

   

7,286

   

-

   

29,357

Other Non-Current Taxes (Non-Current Impact of the Tax Cut Jobs Act)

   

 

(513,404)

   

 

-

   

 

(513,404)

   

 

-

Changes in Components of Working Capital and Other Assets and Liabilities

                       

Accounts Receivable

   

366,686

   

220,939

   

392,131

   

232,799

Inventories

   

156,874

   

(33,131)

   

174,548

   

(170,694)

Accounts Payable

   

(211,298)

   

(127,165)

   

(324,192)

   

74,048

Accrued Taxes Payable

   

13,970

   

21,214

   

63,937

   

(92,782)

Other Assets

   

574,669

   

28,110

   

658,609

   

40,636

Other Liabilities

   

20,647

   

53,024

   

89,871

   

16,225

Changes in Components of Working Capital Associated with Investing and Financing Activities

   

 

(210,365)

   

 

36,342

   

 

(89,992)

   

 

156,102

 

Discretionary Cash Flow (Non-GAAP)

 

$

1,541,747

 

$

1,045,295

 

$

4,839,532

 

$

2,748,953

                         

Discretionary Cash Flow (Non-GAAP) - Percentage Increase

   

47%

         

76%

     
                         

Discretionary Cash Flow (Non-GAAP)

     

$

4,839,532

     

Less:  

                       

Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a)

   

(4,228,859)

     

Dividends Paid (GAAP) 

         

(386,531)

     

Free Cash Flow (Non-GAAP)

       

$

224,142

     
                         
                         

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

                         

Total Expenditures (GAAP)

       

$

4,612,746

     

Less:  

                       

          Asset Retirement Costs

         

(55,592)

     

          Non-Cash Acquisition Costs of Unproved Properties

   

(255,711)

     

          Acquisition Costs of Proved Properties

       

(72,584)

     

Total Cash Expenditures Excluding Acquisitions (Non-GAAP) 

 

$

4,228,859

     

 

 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net,

Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, 

Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX)

 (Non-GAAP) to Net Income (Loss) (GAAP)

(Unaudited; in thousands)

                       

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

                       
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

                       

Net Income (Loss) (GAAP)

$

2,430,468

 

$

(142,352)

 

$

2,582,579

 

$

(1,096,686)

                       

Adjustments:

                     

     Interest Expense, Net

 

63,362

   

71,325

   

274,372

   

281,681

     Income Tax Provision (Benefit)

 

(2,017,115)

   

(51,658)

   

(1,921,397)

   

(460,819)

     Depreciation, Depletion and Amortization

 

881,745

   

862,524

   

3,409,387

   

3,553,417

     Exploration Costs

 

22,941

   

39,110

   

145,342

   

124,953

     Dry Hole Costs

 

4,532

   

193

   

4,609

   

10,657

     Impairments 

 

153,442

   

297,946

   

479,240

   

620,267

            EBITDAX (Non-GAAP)

 

1,539,375

   

1,077,088

   

4,974,132

   

3,033,470

     Total (Gains) Losses on MTM Commodity Derivative Contracts  

 

45,032

   

65,787

   

(19,828)

   

99,608

     Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts

 

2,708

   

-

   

7,438

   

(22,219)

     (Gains) Losses on Asset Dispositions, Net

 

65,220

   

(104,034)

   

99,096

   

(205,835)

                       

Adjusted EBITDAX (Non-GAAP)

$

1,652,335

 

$

1,038,841

 

$

5,060,838

 

$

2,905,024

                       

Adjusted EBITDAX (Non-GAAP) - Percentage Increase

 

59%

         

74%

     

 

 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of Net Debt (Non-GAAP) and Total

Capitalization (Non-GAAP) as Used in the Calculation of

The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to

Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)

(Unaudited; in millions, except ratio data)

           

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

           
 

At

 

At

 

December 31,

 

December 31,

 

2017

 

2016

           

Total Stockholders' Equity - (a)

$

16,283

 

$

13,982

           

Current and Long-Term Debt (GAAP) - (b)

 

6,387

   

6,986

Less: Cash 

 

(834)

   

(1,600)

Net Debt (Non-GAAP) - (c)

 

5,553

   

5,386

           

Total Capitalization (GAAP) - (a) + (b)

$

22,670

 

$

20,968

           

Total Capitalization (Non-GAAP) - (a) + (c)

$

21,836

 

$

19,368

           

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

 

28%

   

33%

           

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

 

25%

   

28%

 

 
 

EOG RESOURCES, INC.

Reserves Supplemental Data

(Unaudited)

                 

2017 NET PROVED RESERVES RECONCILIATION SUMMARY  

   
 

 United 

     

 Other 

     
 

 States 

 

Trinidad

 

 International 

 

 Total 

 

CRUDE OIL & CONDENSATE (MMBbl)

               

Beginning Reserves

1,168.5

 

0.8

 

8.3

 

1,177.6

 

Revisions 

58.0

 

0.1

 

(0.2)

 

57.9

 

Purchases in place

1.1

 

-

 

-

 

1.1

 

Extensions, discoveries and other additions

207.1

 

0.3

 

0.1

 

207.5

 

Sales in place

(8.4)

 

-

 

-

 

(8.4)

 

Production 

(122.2)

 

(0.3)

 

(0.2)

 

(122.7)

 

Ending Reserves

1,304.1

 

0.9

 

8.0

 

1,313.0

 
 

NATURAL GAS LIQUIDS (MMBbl)

               

Beginning Reserves

416.4

 

-

 

-

 

416.4

 

Revisions 

46.9

 

-

 

-

 

46.9

 

Purchases in place

0.4

 

-

 

-

 

0.4

 

Extensions, discoveries and other additions

75.0

 

-

 

-

 

75.0

 

Sales in place

(2.9)

 

-

 

-

 

(2.9)

 

Production 

(32.3)

 

-

 

-

 

(32.3)

 

Ending Reserves

503.5

 

-

 

-

 

503.5

 
 

NATURAL GAS (Bcf) 

               

Beginning Reserves 

3,021.2

 

280.9

 

15.8

 

3,317.9

 

Revisions 

602.8

 

(27.4)

 

8.6

 

584.0

 

Purchases in place

4.8

 

-

 

-

 

4.8

 

Extensions, discoveries and other additions

619.3

 

174.2

 

35.9

 

829.4

 

Sales in place

(56.4)

 

-

 

-

 

(56.4)

 

Production 

(293.2)

 

(114.3)

 

(9.1)

 

(416.6)

 

Ending Reserves

3,898.5

 

313.4

 

51.2

 

4,263.1

 
 

OIL EQUIVALENTS (MMBoe) 

               

Beginning Reserves 

2,088.4

 

47.7

 

10.9

 

2,147.0

 

Revisions 

205.3

 

(4.5)

 

1.2

 

202.0

 

Purchases in place

2.3

 

-

 

-

 

2.3

 

Extensions, discoveries and other additions

385.4

 

29.3

 

6.1

 

420.8

 

Sales in place

(20.7)

 

-

 

-

 

(20.7)

 

Production 

(203.4)

 

(19.4)

 

(1.6)

 

(224.4)

 

Ending Reserves

2,457.3

 

53.1

 

16.6

 

2,527.0

 
 

Net Proved Developed Reserves (MMBoe) 

               

At December 31, 2016

1,038.5

 

44.5

 

10.9

 

1,093.9

 

At December 31, 2017

1,300.7

 

50.8

 

12.8

 

1,364.3

 
 

2017 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) 

   
 

 United 

     

 Other 

     
 

 States 

 

Trinidad

 

 International 

 

 Total 

 
 

Acquisition Cost of Unproved Properties

$       424.1

 

$          2.4

 

$            -

 

$       426.5

 

Exploration Costs

144.5

 

62.6

 

16.5

 

223.6

 

Development Costs

3,540.7

 

107.2

 

13.2

 

3,661.1

 

Total Drilling

4,109.3

 

172.2

 

29.7

 

4,311.2

 

Acquisition Cost of Proved Properties

72.6

 

-

 

-

 

72.6

 

Asset Retirement Costs 

50.2

 

2.3

 

3.1

 

55.6

 

Total Exploration & Development Expenditures 

4,232.1

 

174.5

 

32.8

 

4,439.4

 

Gathering, Processing and Other

173.0

 

0.1

 

0.2

 

173.3

 

Total Expenditures

4,405.1

 

174.6

 

33.0

 

4,612.7

 

Proceeds from Sales in Place

(226.6)

 

-

 

-

 

(226.6)

 

Net Expenditures

$    4,178.5

 

$       174.6

 

$         33.0

 

$    4,386.1

 
 

RESERVE REPLACEMENT COSTS ($ / Boe ) * 

               

All-in Total, Net of Revisions 

$         6.58

 

$         6.94

 

$         4.07

 

$         6.56

 

All-in Total, Excluding Revisions Due to Price

$         8.88

 

$         6.94

 

$         4.07

 

$         8.71

 
 

RESERVE REPLACEMENT *

               

Drilling Only

190%

 

151%

 

381%

 

188%

 

All-in Total, Net of Revisions & Dispositions  

281%

 

128%

 

456%

 

269%

 

All-in Total, Excluding Revisions Due to Price

206%

 

128%

 

456%

 

201%

 

All-in Total, Liquids

244%

 

133%

 

-50%

 

244%

 
 

*   See attached reconciliation schedule for calculation methodology

 

 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP)

As Used in the Calculation of Reserve Replacement Costs ($ / BOE)

To Total Costs Incurred in Exploration and Development Activities (GAAP)

(Unaudited; in millions, except ratio information)

                 

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

                 

For the Twelve Months Ended December 31, 2017

         
           
 

 United 

     

 Other 

     
 

 States 

 

 Trinidad 

 

 International 

 

 Total 

 
 

Total Costs Incurred in Exploration and Development Activities (GAAP)

$    4,232.1

 

$       174.5

 

$         32.8

 

$    4,439.4

 

Less:  Asset Retirement Costs

(50.2)

 

(2.3)

 

(3.1)

 

(55.6)

 

          Non-Cash Acquisition Costs of Unproved Properties

(255.7)

 

-

 

-

 

(255.7)

 

          Non-Cash Acquisition Costs of Proved Properties

(26.2)

 

-

 

-

 

(26.2)

 

Total Exploration & Development Expenditures (Non-GAAP) (a) 

$    3,900.0

 

$       172.2

 

$         29.7

 

$    4,101.9

 
 

Total Expenditures (GAAP)

$    4,405.1

 

$       174.6

 

$         33.0

 

$    4,612.7

 

Less:  Asset Retirement Costs

(50.2)

 

(2.3)

 

(3.1)

 

(55.6)

 

          Non-Cash Acquisition Costs of Unproved Properties

(255.7)

 

-

 

-

 

(255.7)

 

          Non-Cash Acquisition Costs of Proved Properties

(26.2)

 

-

 

-

 

(26.2)

 

Total Cash Expenditures (Non-GAAP) 

$    4,073.0

 

$       172.3

 

$         29.9

 

$    4,275.2

 
 

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) 

               

Revisions due to price (b)

154.0

 

-

 

-

 

154.0

 

Revisions other than price

51.3

 

(4.5)

 

1.2

 

48.0

 

Purchases in place

2.3

 

-

 

-

 

2.3

 

Extensions, discoveries and other additions (c)

385.4

 

29.3

 

6.1

 

420.8

 

Total Proved Reserve Additions (d) 

593.0

 

24.8

 

7.3

 

625.1

 

Sales in place

(20.7)

 

-

 

-

 

(20.7)

 

Net Proved Reserve Additions From All Sources (e) 

572.3

 

24.8

 

7.3

 

604.4

 
 

Production (f) 

203.4

 

19.4

 

1.6

 

224.4

 
 

RESERVE REPLACEMENT COSTS ($ / Boe)

               

All-in Total, Net of Revisions (a / d)  

$         6.58

 

$         6.94

 

$         4.07

 

$         6.56

 

All-in Total, Excluding Revisions Due to Price (a / (d - b)) 

$         8.88

 

$         6.94

 

$         4.07

 

$         8.71

 
 

RESERVE REPLACEMENT

               

Drilling Only (c / f) 

190%

 

151%

 

381%

 

188%

 

All-in Total, Net of Revisions & Dispositions (e / f) 

281%

 

128%

 

456%

 

269%

 

All-in Total, Excluding Revisions Due to Price ((e - b ) / f) 

206%

 

128%

 

456%

 

201%

 
 

Net Proved Reserve Additions From All Sources - Liquids (MMBbl) 

               

Revisions

104.9

 

0.1

 

(0.2)

 

104.8

 

Purchases in place

1.5

 

-

 

-

 

1.5

 

Extensions, discoveries and other additions (g)

282.1

 

0.3

 

0.1

 

282.5

 

Total Proved Reserve Additions 

388.5

 

0.4

 

(0.1)

 

388.8

 

Sales in place

(11.3)

 

-

 

-

 

(11.3)

 

Net Proved Reserve Additions From All Sources (h) 

377.2

 

0.4

 

(0.1)

 

377.5

 
 

Production (i)   

154.5

 

0.3

 

0.2

 

155.0

 
 

RESERVE REPLACEMENT - LIQUIDS

               

Drilling Only (g / i) 

183%

 

100%

 

50%

 

182%

 

All-in Total, Net of Revisions & Dispositions (h / i) 

244%

 

133%

 

-50%

 

244%

 
 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP)

As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE)

To Total Costs Incurred in Exploration and Development Activities (GAAP)

(Unaudited; in millions, except ratio information)

                 

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

 
                 

For the Twelve Months Ended December 31, 2017

       
             

 Total 

 

PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)

               

Total Costs Incurred in Exploration and Development Activities (GAAP)

           

$    4,439.4

 

Less:  Asset Retirement Costs

           

(55.6)

 

           Acquisition Costs of Unproved Properties

           

(426.5)

 

           Acquisition Cost of Proved Properties

           

(72.6)

 

Drillbit Exploration & Development Expenditures (Non-GAAP) (j)

           

$    3,884.7

 
 

Total Proved Reserves - Extensions, discoveries and other additions (MMBoe)

           

420.8

 

Add: Conversion of proved undeveloped reserves to proved developed

           

152.6

 

Less: Proved undeveloped extensions and discoveries

           

(237.4)

 

Proved Developed Reserves - Extensions and discoveries (MMBoe)

           

336.0

 
 

Total Proved Reserves - Revisions (MMBoe)

           

202.0

 

Less: Proved Undeveloped Reserves - Revisions

           

(33.1)

 

         Proved Developed - Revisions due to price

           

(143.0)

 

Proved Developed Reserves - Revisions other than price (MMBoe)

           

25.9

 
 

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

     

361.9

 
                 

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

     

$       10.73

 

 

 
 

EOG RESOURCES, INC.

Crude Oil and Natural Gas Financial Commodity

Derivative Contracts

                       

EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.  Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors.  EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential).  Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 20, 2018.  The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

                       
                       

Midland Differential Basis Swap Contracts

                 

Weighted

                     

Average Price

                 

Volume

 

Differential

                 

(Bbld) 

 

($/Bbl) 

2018

                   

January 1, 2018 through February 28, 2018 (closed)

           

15,000

 

$                 1.063

March 1, 2018 through December 31, 2018 

           

15,000

 

1.063

                       

2019

                   

January 1, 2019 through December 31, 2019 

           

20,000

 

$                 1.075

                       

EOG has entered into additional crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential).  Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 20, 2018.  The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

                       
                       

Gulf Coast Differential Basis Swap Contracts

                 

Weighted

                     

Average Price

                 

Volume

 

Differential

                 

(Bbld) 

 

($/Bbl) 

2018

                   

January 1, 2018 through February 28, 2018 (closed)

           

37,000

 

$                 3.818

March 1, 2018 through December 31, 2018 

           

37,000

 

3.818

                       

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

                       
                       

Crude Oil Price Swap Contracts

                 

Weighted

                 

Volume

 

Average Price

                 

(Bbld) 

 

($/Bbl) 

2017

                   

January 1, 2017 through February 28, 2017 (closed)

           

35,000

 

$                 50.04

March 1, 2017 through June 30, 2017 (closed)

           

30,000

 

50.05

                       

2018

                   

January 2018 (closed)

           

134,000

 

$                 60.04

February 1, 2018 through December 31, 2018

           

134,000

 

60.04

                       

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

                       

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

                       
                       

Natural Gas Price Swap Contracts

                     

Weighted

                 

Volume

 

Average Price

                 

(MMBtud)

 

($/MMBtu)

2017

                   

March 1, 2017 through November 30, 2017 (closed)

           

30,000

 

$                   3.10

                       

2018

                   

March 1, 2018 through November 30, 2018

           

35,000

 

$                   3.00

                       

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

                       

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts.  The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price.  Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

                       

Natural Gas Option Contracts

         

Call Options Sold

 

Put Options Purchased

             

Weighted

     

Weighted

         

Volume

 

Average Price

 

Volume

 

Average Price

         

(MMBtud) 

 

($/MMBtu) 

 

(MMBtud)

 

($/MMBtu)

2017

                   

March 1, 2017 through November 30, 2017 (closed)

   

213,750

 

$                3.44

 

171,000

 

$                   2.92

                       

2018

                   

March 1, 2018 through November 30, 2018

   

120,000

 

$                3.38

 

96,000

 

$                   2.94

                       

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

                       
                       

Natural Gas Collar Contracts

                 

Weighted Average Price ($/MMBtu)

             

Volume

       
             

(MMBtud) 

 

Ceiling Price

 

Floor Price

2017

                   

March 1, 2017 through November 30, 2017 (closed)

       

80,000

 

$           3.69

 

$                   3.20

                       
                       

Definitions

                   

Bbld         

Barrels per day

                 

$/Bbl

Dollars per barrel

           

MMBtud

Million British thermal units per day

       

$/MMBtu

Dollars per million British thermal units

       

NYMEX

U.S. New York Mercantile Exchange

     

 

 
 

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

 

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

 
 

Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

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

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical

 

Payback ~12 Months on 100% Direct ATROR Wells

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

 
 

Return on Equity / Return on Capital Employed 

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

 

 
 

EOG RESOURCES, INC.

Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss)

(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of

Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP),

Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

(Unaudited; in millions, except ratio data)

                             

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

                             
   

2017

   

2016

   

2015

   

2014

   

2013

Return on Capital Employed (ROCE) (Non-GAAP)

                           
                             

Net Interest Expense (GAAP)

$

274

 

$

282

 

$

237

 

$

201

     

Tax Benefit Imputed (based on 35%) 

 

(96)

   

(99)

   

(83)

   

(70)

     

After-Tax Net Interest Expense (Non-GAAP) - (a) 

$

178

 

$

183

 

$

154

 

$

131

     
                             

Net Income (Loss) (GAAP) - (b)                                                   

$

2,583

 

$

(1,097)

 

$

(4,525)

 

$

2,915

     

Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules)

(1,934)

 (a) 

 

204

 (b) 

 

4,559

 (c) 

 

(199)

 (d) 

   

Adjusted Net Income (Loss) (Non-GAAP) - (c)   

$

649

 

$

(893)

 

$

34

 

$

2,716

     
                             

Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d)   

$

16,283

 

$

13,982

 

$

12,943

 

$

17,713

 

$

15,418

Less: Tax Reform Impact

 

(2,169)

   

-

   

-

   

-

   

-

Total Stockholders' Equity (Non-GAAP) - (e)   

$

14,114

 

$

13,982

 

$

12,943

 

$

17,713

 

$

15,418

                             

Average Total Stockholders' Equity (GAAP) * - (f)   

$

15,133

 

$

13,463

 

$

15,328

 

$

16,566

     
                             

Average Total Stockholders' Equity (Non-GAAP) * - (g)   

$

14,048

 

$

13,463

 

$

15,328

 

$

16,566

     
                             

Current and Long-Term Debt (GAAP) - (h) 

$

6,387

 

$

6,986

 

$

6,655

 

$

5,906

 

$

5,909

Less: Cash

 

(834)

   

(1,600)

   

(719)

   

(2,087)

   

(1,318)

Net Debt (Non-GAAP) - (i) 

$

5,553

 

$

5,386

 

$

5,936

 

$

3,819

 

$

4,591

                             

Total Capitalization (GAAP) - (d) + (h)  

$

22,670

 

$

20,968

 

$

19,598

 

$

23,619

 

$

21,327

                             

Total Capitalization (Non-GAAP) - (e) + (i) 

$

19,667

 

$

19,368

 

$

18,879

 

$

21,532

 

$

20,009

                             

Average Total Capitalization (Non-GAAP) * - (j)   

$

19,518

 

$

19,124

 

$

20,206

 

$

20,771

     
                             

ROCE (GAAP Net Income) - [(a) + (b)] / (j)       

 

14.1%

   

-4.8%

   

-21.6%

   

14.7%

     
                             

ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j)       

 

4.2%

   

-3.7%

   

0.9%

   

13.7%

     
                             

Return on Equity (ROE)

                           
                             

ROE (GAAP) (GAAP Net Income) - (b) / (f)

 

17.1%

   

-8.1%

   

-29.5%

   

17.6%

     
                             

ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g)

 

4.6%

   

-6.6%

   

0.2%

   

16.4%

     
                             

* Average for the current and immediately preceding year

                 
                             
                             

Adjustments to Net Income (Loss) (GAAP)

                     
                             
                             

(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017:

             
   

Year Ended December 31, 2017

           
   

 Before 

   

 Income Tax  

   

 After 

           
   

 Tax 

   

 Impact 

   

 Tax 

           

Adjustments:

                           

    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

(12)

 

$

4

 

$

(8)

           

    Add:   Impairments of Certain Assets

 

261

   

(93)

   

168

           

    Add:   Net Losses on Asset Dispositions

 

99

   

(35)

   

64

           

    Add:   Legal Settlement - Early Lease Termination

 

10

   

(4)

   

6

           

    Add:   Joint Venture Transaction Costs

 

3

   

(1)

   

2

           

    Add:   Joint Interest Billings Deemed Uncollectible

 

5

   

(2)

   

3

           

    Less:  Tax Reform Impact

 

-

   

(2,169)

   

(2,169)

           

Total

$

366

 

$

(2,300)

 

$

(1,934)

           
                             

(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016:

             
   

Year Ended December 31, 2016

           
   

 Before 

   

 Income Tax  

   

 After 

           
   

 Tax 

   

 Impact 

   

 Tax 

           

Adjustments:

                           

    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

77

 

$

(28)

 

$

49

           

    Add:   Impairments of Certain Assets

 

321

   

(113)

   

208

           

    Less:  Net Gains on Asset Dispositions

 

(206)

   

62

   

(144)

           

    Add:   Trinidad Tax Settlement

 

-

   

43

   

43

           

    Add:   Voluntary Retirement Expense

 

42

   

(15)

   

27

           

    Add:   Acquisition - State Apportionment Change

 

-

   

16

   

16

           

    Add:   Acquisition Costs

 

5

   

-

   

5

           

Total

$

239

 

$

(35)

 

$

204

           
                             

(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015:

             
   

Year Ended December 31, 2015

           
   

 Before 

   

 Income Tax  

   

 After 

           
   

 Tax 

   

 Impact 

   

 Tax 

           

Adjustments:

                           

    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

668

 

$

(238)

 

$

430

           

    Add:   Impairments of Certain Assets

 

6,308

   

(2,183)

   

4,125

           

    Less:  Texas Margin Tax Rate Reduction

 

-

   

(20)

   

(20)

           

    Add:   Legal Settlement - Early Leasehold Termination

 

19

   

(6)

   

13

           

    Add:   Severance Costs

 

9

   

(3)

   

6

           

    Add:   Net Losses on Asset Dispositions

 

9

   

(4)

   

5

           

Total

$

7,013

 

$

(2,454)

 

$

4,559

           
                             

(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014:

             
   

Year Ended December 31, 2014

           
   

 Before 

   

 Income Tax  

   

 After 

           
   

 Tax 

   

 Impact 

   

 Tax 

           

Adjustments:

                           

    Less:  Mark-to-Market Commodity Derivative Contracts Impact

$

(800)

 

$

285

 

$

(515)

           

    Add:   Impairments of Certain Assets

 

824

   

(271)

   

553

           

    Less:  Net Gains on Asset Dispositions

 

(508)

   

21

   

(487)

           

    Add:   Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years

 

-

   

250

   

250

           

Total

$

(484)

 

$

285

 

$

(199)

           

 

 
 

EOG RESOURCES, INC.

First Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing

                       

     (a)  First Quarter and Full Year 2018 Forecast

         
                       

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

                       

     (b)  Benchmark Commodity Pricing

           
                       

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

                       

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

                       
 

 

Estimated Ranges

 

 

(Unaudited)

   

1Q 2018

   

Full Year 2018

Daily Sales Volumes

                     

     Crude Oil and Condensate Volumes (MBbld)

                     

          United States

 

350.0

-

 

360.0

   

387.0

-

 

401.0

          Trinidad

 

0.5

-

 

0.7

   

0.4

-

 

0.6

          Other International

 

0.0

-

 

5.0

   

2.0

-

 

4.0

               Total

 

350.5

-

 

365.7

   

389.4

-

 

405.6

                       

     Natural Gas Liquids Volumes (MBbld)

                     

               Total

 

93.0

-

 

103.0

   

100.0

-

 

110.0

                       

     Natural Gas Volumes (MMcfd)

                     

          United States

 

825

-

 

865

   

900

-

 

950

          Trinidad

 

280

-

 

310

   

250

-

 

290

          Other International

 

25

-

 

35

   

28

-

 

38

               Total

 

1,130

-

 

1,210

   

1,178

-

 

1,278

                       

     Crude Oil Equivalent Volumes (MBoed)  

                     

          United States

 

580.5

-

 

607.2

   

637.0

-

 

669.3

          Trinidad

 

47.2

-

 

52.4

   

42.1

-

 

48.9

          Other International

 

4.2

-

 

10.8

   

6.7

-

 

10.3

               Total

 

631.9

-

 

670.4

   

685.8

-

 

728.5

                       
 

 

 

Estimated Ranges

 

 

(Unaudited)

 

1Q 2018

   

Full Year 2018

Operating Costs

                     

     Unit Costs ($/Boe)

                     

          Lease and Well

$

4.70

-

$

5.10

 

$

4.20

-

$

4.80

          Transportation Costs

$

3.00

-

$

3.50

 

$

2.75

-

$

3.25

          Depreciation, Depletion and Amortization

$

13.00

-

$

13.40

 

$

13.10

-

$

13.50

                       

Expenses ($MM)

                     

     Exploration, Dry Hole and Impairment

$

90

-

$

120

 

$

375

-

$

425

     General and Administrative

$

100

-

$

110

 

$

415

-

$

445

     Gathering and Processing 

$

95

-

$

105

 

$

430

-

$

470

     Capitalized Interest

$

6

-

$

8

 

$

27

-

$

32

     Net Interest

$

60

-

$

62

 

$

234

-

$

242

                       

Taxes Other Than Income (% of Wellhead Revenue)

 

6.6%

-

 

7.0%

   

6.5%

-

 

6.9%

                       

Income Taxes

                     

     Effective Rate 

 

20%

-

 

25%

   

20%

-

 

25%

     Current Tax (Benefit) / Expense ($MM)

$

(90)

-

$

(55)

 

$

(310)

-

$

(270)

                       

Capital Expenditures (Excluding Acquisitions, $MM)

                     

     Exploration and Development, Excluding Facilities

           

$

4,500

-

$

4,800

     Exploration and Development Facilities

           

$

600

-

$

650

     Gathering, Processing and Other

           

$

300

-

$

350

                       

Pricing - (Refer to Benchmark Commodity Pricing in text)

                     

     Crude Oil and Condensate ($/Bbl)

                     

          Differentials

                     

               United States - above (below) WTI

$

0.00

-

$

1.50

 

$

(1.00)

-

$

1.00

               Trinidad - above (below) WTI

$

(11.00)

-

$

(9.00)

 

$

(11.00)

-

$

(9.00)

               Other International - above (below) WTI

$

0.00

-

$

2.00

 

$

0.00

-

$

2.00

                       

     Natural Gas Liquids

                     

          Realizations as % of WTI

 

39%

-

 

45%

   

40%

-

 

46%

                       

     Natural Gas ($/Mcf)

                     

          Differentials

                     

               United States - above (below) NYMEX Henry Hub

$

(0.40)

-

$

0.00

 

$

(0.60)

-

$

0.00

                       

          Realizations

                     

               Trinidad

$

2.50

-

$

2.90

 

$

2.15

-

$

2.75

               Other International

$

4.15

-

$

4.65

 

$

4.00

-

$

5.00

                       

Definitions

                     

$/Bbl        

U.S. Dollars per barrel

             

$/Boe       

U.S. Dollars per barrel of oil equivalent

         

$/Mcf 

U.S. Dollars per thousand cubic feet

         

$MM 

U.S. Dollars in millions

           

MBbld

Thousand barrels per day

           

MBoed

Thousand barrels of oil equivalent per day

       

MMcfd

Million cubic feet per day

           

NYMEX

U.S. New York Mercantile Exchange

         

WTI  

West Texas Intermediate

           

 

 
 

EOG RESOURCES, INC.

Fourth Quarter 2017 Well Results by Play

(Unaudited)

                             
   

Wells Completed

     

Initial 30-Day Average Production Rate

   

Gross

 

Net

 

Lateral
Length
(ft)

 

Crude Oil and
Condensate
(Bbld) (A)

 

Natural Gas
Liquids
(Bbld)(A)

 

 Natural Gas
(MMcfd) (A)

 

Crude Oil
Equivalent
(Boed)(B)

Delaware Basin

                           

Wolfcamp

 

51

 

45

 

6,000

 

1,410

 

310

 

2.5

 

2,145

Bone Spring

 

9

 

9

 

6,700

 

1,085

 

160

 

1.3

 

1,470

Leonard

 

5

 

5

 

8,700

 

1,230

 

265

 

2.2

 

1,865

                             

Powder River Basin Turner

 

9

 

7

 

7,700

 

990

 

375

 

4.7

 

2,150

                             

DJ Basin Codell

 

3

 

2

 

9,100

 

950

 

105

 

0.4

 

1,120

                             

South Texas Eagle Ford

 

74

 

70

 

7,400

 

1,525

 

195

 

1.1

 

1,915

                             

South Texas Austin Chalk

 

4

 

4

 

5,300

 

2,280

 

430

 

2.5

 

3,130

                             

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

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

 

SOURCE EOG Resources, Inc.

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