email   rss   
Press Releases
EOG Resources Announces Second Quarter 2017 Results

Click here for PDF version

HOUSTON, Aug. 1, 2017 /PRNewswire/ -- 

  • Exceeds Crude Oil, NGL and Natural Gas Production Targets
  • Delivers Per-Unit Lease and Well, Transportation and DD&A Rates Below Targets
  • Increases 2017 U.S. Crude Oil Growth Forecast to 20 Percent from 18 Percent
  • Maintains 2017 Capital Expenditure Guidance
  • Reduces First-Half 2017 Completed Well Costs by an Average of 7 Percent

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2017 net income of $23.1 million, or $0.04 per share. This compares to a second quarter 2016 net loss of $292.6 million, or $0.53 per share. 

Adjusted non-GAAP net income for the second quarter 2017 was $46.7 million, or $0.08 per share, compared to an adjusted non-GAAP net loss of $209.7 million, or $0.38 per share, for the same prior year period.  Adjusted non-GAAP net income (loss) is calculated by matching commodity derivative contract realizations to settlement months and making certain other adjustments in order to exclude non-recurring items.  (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Increased crude oil volumes and higher commodity prices resulted in increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the second quarter 2017 compared to the second quarter 2016.  (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)

Operational Highlights

EOG grew second quarter total crude oil volumes 25 percent to 334,700 barrels of oil per day (Bopd), setting a company oil production record.  Natural gas liquids (NGLs) and natural gas production also exceeded targets, contributing to 10 percent total company production growth compared to the second quarter 2016.  The company also delivered per-unit costs for lease and well, transportation and depreciation, depletion and amortization below targets.

"EOG's premium drilling strategy continues to drive outperformance every quarter, delivering strong production growth with industry-leading capital efficiency," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "Our permanent shift to premium drilling, driven by an organic exploration focus and best-in-class technology, is a sustainable competitive advantage."

Updated 2017 Growth Targets

As a result of strong well productivity improvements, EOG increased 2017 production growth targets while maintaining its current plan of completing 480 net wells with capital expenditures of $3.7 to $4.1 billion.  The company increased its full-year 2017 U.S. crude oil growth target to 20 percent from 18 percent and total company production growth target to seven percent from five percent. In addition to delivering strong growth, EOG is actively engaged in a robust exploration program to lease and test multiple new prospects.

"EOG can generate high returns at relatively low oil prices, and our disciplined investment strategy has positioned the company on a strong financial footing," Thomas said.  "By applying industry-leading technology and geoscience to our acreage concentrated in the sweet spots of the largest oil plays in the U.S., EOG can continue to grow at strong rates within cash flow."

Delaware Basin

In the second quarter 2017, EOG continued its exploration and development program across the Delaware Basin. 

EOG completed 25 wells in the Delaware Basin Wolfcamp in the second quarter with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 3,010 barrels of oil equivalent per day (Boed), or 1,945 Bopd, 480 barrels per day (Bpd) of NGLs and 3.5 million cubic feet per day (MMcfd) of natural gas.  In Lea County, NM, EOG completed a four-well pattern, the Rattlesnake 28 Fed Com 706H-709H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 3,870 Boed, or 2,545 Bopd, 600 Bpd of NGLs and 4.4 MMcfd of natural gas.

In the Delaware Basin Bone Spring, EOG completed 19 wells in the second quarter with an average treated lateral length of 5,600 feet per well and average 30-day initial production rates per well of 2,130 Boed, or 1,515 Bopd, 275 Bpd of NGLs and 2.0 MMcfd of natural gas.  In Lea County, NM, EOG completed a three-well pattern, the Neptune 10 State Com 503H-505H, with an average treated lateral length of 9,700 feet per well and average 30-day initial production rates per well of 3,620 Boed, or 2,790 Bopd, 375 Bpd of NGLs and 2.7 MMcfd of natural gas.

In the Delaware Basin Leonard, EOG completed three wells in the second quarter with an average treated lateral length of 5,400 feet per well and average 30-day initial production rates per well of 1,615 Boed, or 1,075 Bopd, 245 Bpd of NGLs and 1.8 MMcfd of natural gas. 

South Texas Eagle Ford

EOG's South Texas Eagle Ford generated strong initial production performance during the second quarter as EOG continued to apply its precision targeting concepts across its expansive acreage position in the black oil window of the play.

In the second quarter, EOG completed 51 wells in the Eagle Ford with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 1,960 Boed, or 1,520 Bopd, 225 Bpd of NGLs and 1.3 MMcfd of natural gas.  In Karnes County, EOG completed a three-well pattern, the Lynch Unit 2H-4H, with an average treated lateral length of 5,800 feet per well and average 30-day initial production rates per well of 3,245 Boed, or 2,555 Bopd, 350 Bpd of NGLs and 2.0 MMcfd of natural gas.  In Gonzales County, EOG completed a four-well pattern, the Olympic A 1H–D 4H, with an average treated lateral length of 6,600 feet per well and average 30-day initial production rates per well of 2,910 Boed, or 2,160 Bopd, 380 Bpd of NGLs and 2.2 MMcfd of natural gas.  In DeWitt County, EOG completed a five-well pattern, the Dio Unit 11H-15H, with an average treated lateral length of 5,100 feet per well and average 30-day initial production rates per well of 2,840 Boed, or 2,135 Bopd, 355 Bpd of NGLs and 2.1 MMcfd of natural gas. 

South Texas Austin Chalk

In the second quarter 2017, testing continued in the South Texas Austin Chalk.  EOG completed nine wells in Karnes County with an average treated lateral length of 4,000 feet per well and average 30-day initial production rates per well of 2,645 Boed, or 2,150 Bopd, 255 Bpd of NGLs and 1.5 MMcfd of natural gas.

Bakken and Powder River Basin

During the second quarter, EOG continued development of its premium oil plays across the Rocky Mountain region.

In the North Dakota Bakken, EOG completed 22 wells in the second quarter with an average treated lateral length of 8,400 feet per well and average 30-day initial production rates per well of 1,450 Boed, or 1,175 Bopd, 150 Bpd of NGLs and 0.7 MMcfd of natural gas.  Of particular note is a four-well pattern in the Antelope field in McKenzie County, the Clarks Creek 73, 74, 75 and 110-0719H, completed with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 2,965 Boed, or 2,075 Bopd, 500 Bpd of NGLs and 2.3 MMcfd of natural gas.

In the Powder River Basin Turner, EOG completed eight wells in the second quarter with an average treated lateral length of 8,700 feet per well and average 30-day initial production rates per well of 1,745 Boed, or 910 Bopd, 285 Bpd of NGLs and 3.3 MMcfd of natural gas. 

In the DJ Basin, EOG completed 10 wells in the second quarter with an average treated lateral length of 9,000 feet per well and average 30-day initial production rates per well of 885 Boed, or 770 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas. 

Trinidad

In June 2017, EOG signed a new multi-year contract under which EOG will supply future natural gas volumes to the National Gas Company of Trinidad and Tobago Limited beginning in 2019.  The new contract opens opportunities for additional investments that can deliver rates of return competitive with EOG's premier on-shore oil plays.

Hedging Activity

During the second quarter ended June 30, 2017, EOG entered into crude oil derivative contracts in order to fix the differential between pricing in Midland, TX and Cushing, OK.  For the period January 1 through December 31, 2018, EOG entered into crude oil basis swap contracts for 15,000 Bopd at a weighted average price differential between Midland, TX and Cushing, OK of $1.063 per barrel.  In addition, for the period January 1 through December 31, 2019, EOG entered into crude oil basis swap contracts for 20,000 Bopd at a weighted average price differential between Midland, TX and Cushing, OK of $1.075 per barrel.

During the second quarter ended June 30, 2017, EOG did not enter into additional natural gas derivative contracts.

A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.  

Capital Structure and Asset Sales

At June 30, 2017, EOG's total debt outstanding was $7.0 billion for a debt-to-total capitalization ratio of 33 percent.  Considering cash on the balance sheet at the end of the second quarter, EOG's net debt was $5.3 billion for a net debt-to-total capitalization ratio of 28 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales in the first six months of 2017 totaled $175 million.

Conference Call August 2, 2017

EOG's second quarter 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 2, 2017.  To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.  The webcast will be archived on EOG's website through August 2, 2018.

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."

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 and costs, 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.  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 13 through 22 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, 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, 2016, 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

 

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

 

Six Months Ended

 

June 30,

 

June 30,

 

2017

 

2016

 

2017

 

2016

                       

Net Operating Revenues and Other

$

2,612.5

 

$

1,775.7

 

$

5,223.0

 

$

3,130.1

Net Income (Loss)

$

23.1

 

$

(292.6)

 

$

51.6

 

$

(764.3)

Net Income (Loss) Per Share 

                     

        Basic

$

0.04

 

$

(0.53)

 

$

0.09

 

$

(1.40)

        Diluted

$

0.04

 

$

(0.53)

 

$

0.09

 

$

(1.40)

Average Number of Common Shares

                     

        Basic

 

574.4

   

547.3

   

574.2

   

547.0

        Diluted

 

578.5

   

547.3

   

578.6

   

547.0

                       
                       

Summary Income Statements

(Unaudited; in thousands, except per share data)

                       
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2017

 

2016

 

2017

 

2016

Net Operating Revenues and Other

             

        Crude Oil and Condensate

$

1,445,454

 

$

1,059,690

 

$

2,875,515

 

$

1,813,401

        Natural Gas Liquids

 

146,907

   

111,643

   

300,351

   

186,962

        Natural Gas

 

224,008

   

155,983

   

454,610

   

321,486

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

 

9,446

   

(44,373)

   

71,466

   

(38,938)

        Gathering, Processing and Marketing

 

778,797

   

485,256

   

1,505,334

   

819,209

        Losses on Asset Dispositions, Net

 

(8,916)

   

(15,550)

   

(25,674)

   

(6,403)

        Other, Net

 

16,776

   

23,091

   

41,435

   

34,372

               Total

 

2,612,472

   

1,775,740

   

5,223,037

   

3,130,089

Operating Expenses

                     

        Lease and Well

 

255,186

   

218,393

   

510,963

   

459,258

        Transportation Costs

 

186,356

   

179,471

   

365,070

   

369,925

        Gathering and Processing Costs

 

34,746

   

29,226

   

72,890

   

57,750

        Exploration Costs

 

34,711

   

30,559

   

91,605

   

60,388

        Dry Hole Costs

 

27

   

(172)

   

27

   

74

        Impairments 

 

78,934

   

72,714

   

272,121

   

144,331

        Marketing Costs

 

790,599

   

480,046

   

1,527,135

   

820,900

        Depreciation, Depletion and Amortization

 

865,384

   

862,491

   

1,681,420

   

1,791,382

        General and Administrative

 

108,507

   

97,705

   

205,745

   

198,236

        Taxes Other Than Income

 

130,114

   

93,480

   

260,407

   

154,159

               Total

 

2,484,564

   

2,063,913

   

4,987,383

   

4,056,403

                       

Operating Income (Loss)

 

127,908

   

(288,173)

   

235,654

   

(926,314)

                       

Other Income (Expense), Net

 

4,972

   

(20,996)

   

8,123

   

(25,433)

                       

Income (Loss) Before Interest Expense and Income Taxes

132,880

   

(309,169)

   

243,777

   

(951,747)

                       

Interest Expense, Net

 

70,413

   

71,108

   

141,928

   

139,498

                       

Income (Loss) Before Income Taxes

 

62,467

   

(380,277)

   

101,849

   

(1,091,245)

                       

Income Tax Provision (Benefit)

 

39,414

   

(87,719)

   

50,279

   

(326,911)

                       

Net Income (Loss)

$

23,053

 

$

(292,558)

 

$

51,570

 

$

(764,334)

                       

Dividends Declared per Common Share

$

0.1675

 

$

0.1675

 

$

0.3350

 

$

0.3350

 
 

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)

                       
 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2017

 

2016

 

2017

 

2016

Wellhead Volumes and Prices

     

Crude Oil and Condensate Volumes (MBbld) (A)

     

      United States

 

333.1

   

265.4

   

322.8

   

265.6

      Trinidad

 

0.8

   

0.8

   

0.8

   

0.8

      Other International (B)

 

0.8

   

1.5

   

1.6

   

1.4

            Total

 

334.7

   

267.7

   

325.2

   

267.8

                       

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

                     

      United States

$

47.51

 

$

43.87

 

$

48.89

 

$

37.36

      Trinidad

 

39.64

   

35.91

   

40.63

   

29.83

      Other International (B)

 

35.13

   

-

   

44.66

   

-

            Composite

 

47.46

   

43.65

   

48.85

   

37.23

                       

Natural Gas Liquids Volumes (MBbld) (A)

                     

      United States

 

86.6

   

84.3

   

82.7

   

81.8

      Other International (B)

 

-

   

-

   

-

   

-

            Total

 

86.6

   

84.3

   

82.7

   

81.8

                       

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

                     

      United States

$

18.65

 

$

14.56

 

$

20.06

 

$

12.54

      Other International (B)

 

-

   

-

   

-

   

-

            Composite

 

18.65

   

14.56

   

20.06

   

12.54

                       

Natural Gas Volumes (MMcfd) (A)

                     

      United States

 

755

   

820

   

742

   

825

      Trinidad

 

320

   

349

   

314

   

355

      Other International (B)

 

21

   

25

   

21

   

25

            Total

 

1,096

   

1,194

   

1,077

   

1,205

                       

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

                     

      United States

$

2.14

 

$

1.18

 

$

2.23

 

$

1.22

      Trinidad

 

2.40

   

1.89

   

2.48

   

1.88

      Other International (B)

 

3.66

   

3.35

   

3.71

   

3.49

            Composite

 

2.25

   

1.44

   

2.33

   

1.47

                       

Crude Oil Equivalent Volumes (MBoed) (D)

                     

      United States 

 

545.6

   

486.3

   

529.2

   

484.9

      Trinidad

 

54.1

   

59.0

   

53.1

   

59.9

      Other International (B)

 

4.2

   

5.8

   

5.1

   

5.6

            Total

 

603.9

   

551.1

   

587.4

   

550.4

                       

Total MMBoe (D)

 

55.0

   

50.1

   

106.3

   

100.2

 

(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)

           
 

June 30,

 

December 31,

 

2017

 

2016

ASSETS

Current Assets

         

     Cash and Cash Equivalents

$

1,649,443

 

$

1,599,895

     Accounts Receivable, Net

 

1,114,454

   

1,216,320

     Inventories

 

336,198

   

350,017

     Assets from Price Risk Management Activities

 

4,746

   

-

     Income Taxes Receivable

 

91,256

   

12,305

     Other

 

187,276

   

206,679

            Total

 

3,383,373

   

3,385,216

           

Property, Plant and Equipment

         

     Oil and Gas Properties (Successful Efforts Method)

 

50,973,760

   

49,592,091

     Other Property, Plant and Equipment

 

3,883,759

   

4,008,564

            Total Property, Plant and Equipment

 

54,857,519

   

53,600,655

     Less:  Accumulated Depreciation, Depletion and Amortization

 

(29,277,359)

   

(27,893,577)

            Total Property, Plant and Equipment, Net

 

25,580,160

   

25,707,078

Deferred Income Taxes

 

16,888

   

16,140

Other Assets

 

283,196

   

190,767

Total Assets

$

29,263,617

 

$

29,299,201

           

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         

     Accounts Payable

$

1,615,170

 

$

1,511,826

     Accrued Taxes Payable

 

155,458

   

118,411

     Dividends Payable

 

96,145

   

96,120

     Liabilities from Price Risk Management Activities

 

-

   

61,817

     Current Portion of Long-Term Debt

 

606,454

   

6,579

     Other

 

249,027

   

232,538

            Total

 

2,722,254

   

2,027,291

           
           

Long-Term Debt

 

6,380,350

   

6,979,779

Other Liabilities

 

1,199,778

   

1,282,142

Deferred Income Taxes

 

5,059,520

   

5,028,408

Commitments and Contingencies

         
           

Stockholders' Equity

         

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized at June 30, 2017,

         

      640,000,000 Shares Authorized at December 31, 2016, 577,711,399 Shares

         

      Issued at June 30, 2017 and 576,950,272 Shares Issued at December 31, 2016

 

205,777

   

205,770

     Additional Paid in Capital

 

5,485,832

   

5,420,385

     Accumulated Other Comprehensive Loss

 

(17,490)

   

(19,010)

     Retained Earnings

 

8,256,359

   

8,398,118

     Common Stock Held in Treasury, 316,339 Shares at June 30, 2017

         

         and 250,155 Shares at December 31, 2016

 

(28,763)

   

(23,682)

            Total Stockholders' Equity

 

13,901,715

   

13,981,581

Total Liabilities and Stockholders' Equity

$

29,263,617

 

$

29,299,201

 
 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

           
 

Six Months Ended

 

June 30,

 

2017

 

2016

Cash Flows from Operating Activities

         

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

         

     Net Income (Loss)

$

51,570

 

$

(764,334)

     Items Not Requiring (Providing) Cash

         

            Depreciation, Depletion and Amortization

 

1,681,420

   

1,791,382

            Impairments 

 

272,121

   

144,331

            Stock-Based Compensation Expenses

 

58,061

   

59,471

            Deferred Income Taxes

 

35,162

   

(384,294)

            Losses on Asset Dispositions, Net

 

25,674

   

6,403

            Other, Net

 

(6,691)

   

29,991

     Dry Hole Costs

 

27

   

74

     Mark-to-Market Commodity Derivative Contracts

         

            Total (Gains) Losses

 

(71,466)

   

38,938

            Net Cash Received from Settlements of Commodity Derivative Contracts 

 

2,591

   

2,852

     Excess Tax Benefits from Stock-Based Compensation

 

-

   

(11,811)

     Other, Net

 

(185)

   

5,008

     Changes in Components of Working Capital and Other Assets and Liabilities

         

            Accounts Receivable

 

103,786

   

(22,572)

            Inventories

 

(6,129)

   

95,813

            Accounts Payable

 

76,704

   

(203,358)

            Accrued Taxes Payable

 

(39,124)

   

93,320

            Other Assets

 

(61,089)

   

(33,589)

            Other Liabilities

 

(66,869)

   

1,565

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

 

(79,138)

   

(54,453)

Net Cash Provided by Operating Activities

 

1,976,425

   

794,737

           

Investing Cash Flows

         

     Additions to Oil and Gas Properties

 

(1,885,417)

   

(1,143,549)

     Additions to Other Property, Plant and Equipment

 

(88,076)

   

(44,584)

     Proceeds from Sales of Assets

 

175,260

   

252,529

     Changes in Components of Working Capital Associated with Investing Activities

 

79,138

   

54,477

Net Cash Used in Investing Activities

 

(1,719,095)

   

(881,127)

           

Financing Cash Flows

         

     Net Commercial Paper Repayments

 

-

   

(259,718)

     Long-Term Debt Borrowings

 

-

   

991,097

     Long-Term Debt Repayments

 

-

   

(400,000)

     Dividends Paid

 

(192,984)

   

(184,036)

     Excess Tax Benefits from Stock-Based Compensation

 

-

   

11,811

     Treasury Stock Purchased

 

(21,678)

   

(28,755)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

 

9,608

   

10,624

     Debt Issuance Costs

 

-

   

(1,602)

     Repayment of Capital Lease Obligation

 

(3,251)

   

(3,150)

     Other, Net

 

-

   

(24)

Net Cash (Used in) Provided by Financing Activities

 

(208,305)

   

136,247

           

Effect of Exchange Rate Changes on Cash

 

523

   

11,359

           

Increase in Cash and Cash Equivalents

 

49,548

   

61,216

Cash and Cash Equivalents at Beginning of Period

 

1,599,895

   

718,506

Cash and Cash Equivalents at End of Period

$

1,649,443

 

$

779,722

 

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 six-month periods ended June 30, 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 losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017 and to add back the transaction costs for the formation of a joint venture 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 

 

June 30, 2017

 

June 30, 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)

$  62,467

 

$(39,414)

 

$  23,053

 

$      0.04

 

$   (380,277)

 

$  87,719

 

$(292,558)

 

$     (0.53)

Adjustments:

                             

(Gains) Losses on Mark-to-Market Commodity

                             

    Derivative Contracts

(9,446)

 

3,426

 

(6,020)

 

(0.01)

 

44,373

 

(15,819)

 

28,554

 

0.05

Net Cash Received from (Payments for)

                             

   Settlements of Commodity Derivative

                             

    Contracts

679

 

(245)

 

434

 

-

 

(14,835)

 

5,289

 

(9,546)

 

(0.01)

Add:  Net Losses on Asset Dispositions

8,916

 

(3,151)

 

5,765

 

0.01

 

15,550

 

(7,378)

 

8,172

 

0.01

Add:  Impairments

23,397

 

(8,477)

 

14,920

 

0.03

 

-

 

-

 

-

 

-

Add:  Trinidad Tax Settlement

-

 

-

 

-

 

-

 

-

 

43,000

 

43,000

 

0.08

Add:  Voluntary Retirement Expense

-

 

-

 

-

 

-

 

19,663

 

(7,010)

 

12,653

 

0.02

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

 

-

 

-

 

-

 

-

 

-

Adjustments to Net Income 

36,804

 

(13,199)

 

23,605

 

0.04

 

64,751

 

18,082

 

82,833

 

0.15

                               

Adjusted Net Income (Loss) (Non-GAAP)

$  99,271

 

$(52,613)

 

$  46,658

 

$      0.08

 

$   (315,526)

 

$105,801

 

$(209,725)

 

$     (0.38)

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

574,439

             

547,335

       Diluted

           

578,483

             

547,335

                               

Average Number of Common Shares (Non-GAAP)

                             

   Basic

           

574,439

             

547,335

   Diluted

           

578,483

             

547,335

                               
                               
                               
 

Six Months Ended 

 

Six Months Ended 

 

June 30, 2017

 

June 30, 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)

$101,849

 

$(50,279)

 

$  51,570

 

$      0.09

 

$(1,091,245)

 

$326,911

 

$(764,334)

 

$     (1.40)

Adjustments:

                             

(Gains) Losses on Mark-to-Market Commodity

                             

    Derivative Contracts

(71,466)

 

25,617

 

(45,849)

 

(0.08)

 

38,938

 

(13,881)

 

25,057

 

0.05

Net Cash Received from Settlements of

                             

    Commodity Derivative Contracts

2,591

 

(929)

 

1,662

 

-

 

2,852

 

(1,017)

 

1,835

 

-

Add:  Net Losses on Asset Dispositions

25,674

 

(8,887)

 

16,787

 

0.03

 

6,403

 

(4,168)

 

2,235

 

-

Add:  Impairments

161,148

 

(57,764)

 

103,384

 

0.18

 

-

 

-

 

-

 

-

Add:  Trinidad Tax Settlement

-

 

-

 

-

 

-

 

-

 

43,000

 

43,000

 

0.08

Add:  Voluntary Retirement Expense

-

 

-

 

-

 

-

 

42,054

 

(14,992)

 

27,062

 

0.05

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

 

-

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

131,205

 

(46,715)

 

84,490

 

0.14

 

90,247

 

8,942

 

99,189

 

0.18

                               

Adjusted Net Income (Loss) (Non-GAAP)

$233,054

 

$(96,994)

 

$136,060

 

$      0.23

 

$(1,000,998)

 

$335,853

 

$(665,145)

 

$     (1.22)

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

574,162

             

547,029

       Diluted

           

578,573

             

547,029

                               

Average Number of Common Shares (Non-GAAP)

                             

   Basic

           

574,162

             

547,029

   Diluted

           

578,573

             

547,029

 

EOG RESOURCES, INC.

Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)

to Net Cash Provided By Operating Activities (GAAP)

(Unaudited; in thousands)

 

The following chart reconciles the three-month and six-month periods ended June 30, 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, 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 management uses this information for comparative purposes within the industry.

                         
   

Three Months Ended

 

Six Months Ended

   

June 30,

 

June 30,

   

2017

 

2016

 

2017

 

2016

                         

Net Cash Provided by Operating Activities (GAAP)

$

1,078,376

 

$

503,146

 

$

1,976,425

 

$

794,737

                         

Adjustments:

                       

Exploration Costs (excluding Stock-Based Compensation Expenses) 

   

29,402

   

25,527

   

80,136

   

48,884

Excess Tax Benefits from Stock-Based Compensation

   

-

   

11,811

   

-

   

11,811

Changes in Components of Working Capital and Other Assets

                       

and Liabilities

                       

Accounts Receivable

   

(75,098)

   

154,970

   

(103,786)

   

22,572

Inventories

   

30,865

   

(38,235)

   

6,129

   

(95,813)

Accounts Payable

   

(56,278)

   

(86,269)

   

(76,704)

   

203,358

Accrued Taxes Payable

   

511

   

(90,860)

   

39,124

   

(93,320)

Other Assets

   

16,412

   

37,535

   

61,089

   

33,589

Other Liabilities

   

15,618

   

6,427

   

66,869

   

(1,565)

Changes in Components of Working Capital Associated with 

                       

Investing and Financing Activities

   

15,814

   

56,681

   

79,138

   

54,453

 

Discretionary Cash Flow (Non-GAAP)

 

$

1,055,622

 

$

580,733

 

$

2,128,420

 

$

978,706

                         

Discretionary Cash Flow (Non-GAAP) - Percentage Increase

   

82%

         

117%

     
 
 

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 six-month periods ended June 30, 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 losses on asset dispositions.  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

 

Six Months Ended

 

June 30,

 

June 30,

 

2017

 

2016

 

2017

 

2016

                       

Net Income (Loss) (GAAP)

$

23,053

 

$

(292,558)

 

$

51,570

 

$

(764,334)

                       

Adjustments:

                     

     Interest Expense, Net

 

70,413

   

71,108

   

141,928

   

139,498

     Income Tax Provision (Benefit)

 

39,414

   

(87,719)

   

50,279

   

(326,911)

     Depreciation, Depletion and Amortization

 

865,384

   

862,491

   

1,681,420

   

1,791,382

     Exploration Costs

 

34,711

   

30,559

   

91,605

   

60,388

     Dry Hole Costs

 

27

   

(172)

   

27

   

74

     Impairments 

 

78,934

   

72,714

   

272,121

   

144,331

             EBITDAX (Non-GAAP)

 

1,111,936

   

656,423

   

2,288,950

   

1,044,428

     Total (Gains) Losses on MTM Commodity Derivative Contracts  

 

(9,446)

   

44,373

   

(71,466)

   

38,938

Net Cash Received from (Payments for) Settlements of Commodity

                     

        Derivative Contracts

 

679

   

(14,835)

   

2,591

   

2,852

     Losses on Asset Dispositions, Net

 

8,916

   

15,550

   

25,674

   

6,403

                       

Adjusted EBITDAX (Non-GAAP)

$

1,112,085

 

$

701,511

 

$

2,245,749

 

$

1,092,621

                       

Adjusted EBITDAX (Non-GAAP) - Percentage Increase

 

59%

         

106%

     

 

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

 

June 30,

 

December 31,

 

2017

 

2016

           

Total Stockholders' Equity - (a)

$

13,902

 

$

13,982

           

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

 

6,987

   

6,986

Less: Cash 

 

(1,649)

   

(1,600)

Net Debt (Non-GAAP) - (c)

 

5,338

   

5,386

           

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

$

20,889

 

$

20,968

           

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

$

19,240

 

$

19,368

           

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

 

33%

   

33%

           

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

 

28%

   

28%

 

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 entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma.  Presented below is a comprehensive summary of EOG's crude oil basis swap contracts through August 1, 2017.  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.

                       
                       

Crude Oil Basis Swap Contracts

                 

Weighted

                     

Average Price

                 

Volume

 

Differential

                 

(Bbld) 

 

($/Bbl) 

2018

                   

January 1, 2018 through December 31, 2018 

   

15,000

 

$           1.063

                       

2019

                   

January 1, 2019 through December 31, 2019 

     

20,000

 

$           1.075

                       

On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain 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 below table.  Presented below is a comprehensive summary of EOG's crude oil price swap contracts through August 1, 2017, 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

                       

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 offsets the remaining 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 August 1, 2017, 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 August 31, 2017 (closed)

   

30,000

 

$             3.10

September 1, 2017 through November 30, 2017

   

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 August 1, 2017, 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 August 31, 2017 (closed)

213,750

 

$             3.44

 

171,000

 

$             2.92

September 1, 2017 through November 30, 2017

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 August 1, 2017, 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 August 31, 2017 (closed)

 

80,000

 

$           3.69

 

$             3.20

September 1, 2017 through November 30, 2017

 

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.

                       
   

2016

   

2015

   

2014

   

2013

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

                     
                       

Net Interest Expense (GAAP)

$

282

 

$

237

 

$

201

     

Tax Benefit Imputed (based on 35%) 

 

(99)

   

(83)

   

(70)

     

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

$

183

 

$

154

 

$

131

     
                       

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

$

(1,097)

 

$

(4,525)

 

$

2,915

     

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

204

 (a) 

 

4,559

 (b) 

 

(199)

 (c) 

   

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

$

(893)

 

$

34

 

$

2,716

     
                       

Total Stockholders' Equity - (d)   

$

13,982

 

$

12,943

 

$

17,713

 

$

15,418

                       

Average Total Stockholders' Equity * - (e)   

$

13,463

 

$

15,328

 

$

16,566

     
                       

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

$

6,986

 

$

6,655

 

$

5,906

 

$

5,909

Less: Cash                                                       

 

(1,600)

   

(719)

   

(2,087)

   

(1,318)

Net Debt (Non-GAAP) - (g) 

$

5,386

 

$

5,936

 

$

3,819

 

$

4,591

                       

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

$

20,968

 

$

19,598

 

$

23,619

 

$

21,327

                       

Total Capitalization (Non-GAAP) - (d) + (g) 

$

19,368

 

$

18,879

 

$

21,532

 

$

20,009

                       

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

$

19,124

 

$

20,206

 

$

20,771

     
                       

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

 

-4.8%

   

-21.6%

   

14.7%

     
                       

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

 

-3.7%

   

0.9%

   

13.7%

     
                       

Return on Equity (ROE)

                     
                       

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

 

-8.1%

   

-29.5%

   

17.6%

     
                       

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

 

-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 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

     
                       

(b) 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

     
                       

(c) 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.

Third Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing

                       

     (a)  Third Quarter and Full Year 2017 Forecast

                       

The forecast items for the third quarter and full year 2017 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)

   

3Q 2017

   

Full Year 2017

Daily Sales Volumes

                     

     Crude Oil and Condensate Volumes (MBbld)

                     

          United States

 

335.0

-

 

345.0

   

332.0

-

 

338.0

          Trinidad

 

0.5

-

 

0.7

   

0.6

-

 

0.8

          Other International

 

0.0

-

 

0.0

   

0.8

-

 

0.8

               Total

 

335.5

-

 

345.7

   

333.4

-

 

339.6

                       

     Natural Gas Liquids Volumes (MBbld)

                     

               Total

 

77.0

-

 

83.0

   

80.0

-

 

83.0

                       

     Natural Gas Volumes (MMcfd)

                     

          United States

 

720

-

 

760

   

730

-

 

760

          Trinidad

 

280

-

 

320

   

295

-

 

310

          Other International

 

15

-

 

30

   

21

-

 

27

               Total

 

1,015

-

 

1,110

   

1,046

-

 

1,097

                       

     Crude Oil Equivalent Volumes (MBoed)  

                     

          United States

 

532.0

-

 

554.7

   

533.7

-

 

547.7

          Trinidad

 

47.2

-

 

54.0

   

49.8

-

 

52.5

          Other International

 

2.5

-

 

5.0

   

4.3

-

 

5.3

               Total

 

581.7

-

 

613.7

   

587.8

-

 

605.5

                       
 

 

Estimated Ranges

 

 

(Unaudited)

 

3Q 2017

   

Full Year 2017

Operating Costs

                     

     Unit Costs ($/Boe)

                     

          Lease and Well

$

4.40

-

$

4.80

 

$

4.40

-

$

4.80

          Transportation Costs

$

3.30

-

$

3.80

 

$

3.30

-

$

3.60

          Depreciation, Depletion and Amortization

$

15.55

-

$

15.95

 

$

15.65

-

$

15.85

                       

Expenses ($MM)

                     

     Exploration, Dry Hole and Impairment

$

90

-

$

120

 

$

390

-

$

420

     General and Administrative

$

100

-

$

110

 

$

380

-

$

400

     Gathering and Processing 

$

28

-

$

32

 

$

130

-

$

140

     Capitalized Interest

$

6

-

$

8

 

$

25

-

$

30

     Net Interest

$

69

-

$

72

 

$

273

-

$

279

                       

Taxes Other Than Income (% of Wellhead Revenue)

 

6.8%

-

 

7.2%

   

6.9%

-

 

7.1%

                       

Income Taxes

                     

     Effective Rate 

 

30%

-

 

35%

   

35%

-

 

40%

     Current Taxes ($MM)

$

0

-

$

35

 

$

10

-

$

50

                       

Capital Expenditures (Excluding Acquisitions, $MM)

                     

     Exploration and Development, Excluding Facilities

           

$

3,000

-

$

3,350

     Exploration and Development Facilities

           

$

475

-

$

510

     Gathering, Processing and Other

           

$

225

-

$

240

                       

Pricing - (Refer toBenchmark Commodity Pricing in text)

                     

     Crude Oil and Condensate ($/Bbl)

                     

          Differentials

                     

               United States - above (below) WTI

$

(1.25)

-

$

(0.25)

 

$

(1.50)

-

$

(0.50)

               Trinidad - above (below) WTI

$

(11.00)

-

$

(9.00)

 

$

(10.00)

-

$

(9.00)

               Other International - above (below) WTI

$

(4.00)

-

$

2.00

 

$

(7.00)

-

$

1.00

                       

     Natural Gas Liquids

                     

          Realizations as % of WTI

 

35%

-

 

41%

   

37%

-

 

41%

                       

     Natural Gas ($/Mcf)

                     

          Differentials

                     

               United States - above (below) NYMEX Henry Hub

$

(1.20)

-

$

(0.70)

 

$

(1.10)

-

$

(0.80)

                       

          Realizations

                     

               Trinidad

$

1.85

-

$

2.25

 

$

2.20

-

$

2.40

               Other International

$

3.80

-

$

4.30

 

$

3.85

-

$

4.15

                       

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.

Top of Page