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EOG Resources Announces Third Quarter 2016 Results; Raises 2020 Outlook and More Than Doubles Permian Basin Net Resource Potential

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HOUSTON, Nov. 3, 2016 /PRNewswire/ --

  • Increases 2020 Crude Oil Production CAGR Outlook to 15 to 25 Percent
  • Expands Delaware Basin Net Resource Potential from 2.35 to 6.0 BnBoe (includes Assets from Recent Yates Transaction)
  • Exceeds U.S. Production Targets
  • Raises 2016 U.S. Crude Oil Production Guidance
  • Updates Year-to-Date Proceeds from Asset Sales to $625 Million

EOG Resources, Inc. (NYSE: EOG) today reported a third quarter 2016 net loss of $190.0 million, or $0.35 per share. This compares to a third quarter 2015 net loss of $4.1 billion, or $7.47 per share. 

Adjusted non-GAAP net loss for the third quarter 2016 was $220.8 million, or $0.40 per share, compared to adjusted non-GAAP net income of $13.5 million, or $0.02 per share, for the same prior year period.  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.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Lower crude oil and natural gas prices more than offset significant well productivity improvements and lease and well cost reductions, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the third quarter 2016 compared to the third quarter 2015.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights
U.S. crude oil volumes of 275,700 barrels of oil per day (Bopd) in the third quarter 2016 exceeded the midpoint of the company's guidance by 3 percent. Compared to the same prior year period, lease and well expenses decreased 18 percent on a per-unit basis.

In the third quarter 2016, total crude oil production increased 1 percent while exploration and development expenditures (excluding property acquisitions) decreased 32 percent, compared to the same period last year.  Natural gas liquids production increased 5 percent, while total natural gas production for the third quarter 2016 decreased 10 percent versus the same prior year period. 

"Even in a low commodity price environment, 2016 is proving to be a breakout year for EOG with record well productivity, sustainable cost reductions and organic growth in all our core plays, coupled with a historic transaction that adds substantial high-return growth potential," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "EOG's third quarter accomplishments reflect the hard work and ingenuity of our great employees and our unique culture."

2020 Crude Oil Production Outlook and 2016 Capital Plan Update
As a result of continued improvements in capital efficiency which have been augmented by the Yates transaction, EOG is increasing its crude oil organic production growth outlook through 2020.  The long term outlook includes growth from key areas such as the Eagle Ford, Delaware Basin, Rockies and the Bakken.  In addition to the growth illustrated in the outlook, the company continues to evaluate high-quality emerging plays through its ongoing exploration efforts.

Assuming balanced spending including dividend payments and a flat $50 West Texas Intermediate crude oil (WTI) price, EOG now expects 15 percent compound annual crude oil production growth through 2020.  If the assumed WTI price is increased to $60, EOG would expect 25 percent compound annual crude oil production growth through 2020.  This reflects an increase from the company's prior outlook of 10 to 20 percent growth at $50 to $60 WTI. 

"EOG's future has never been brighter, and we are already in a position to make a material improvement to the long-term outlook we provided last quarter," Thomas said.  "The company-wide premium drilling strategy and the recently closed Yates transaction are significantly boosting capital efficiency and enabling us to extend our lead in unconventional resource productivity."

For 2016, EOG is increasing its capital spending guidance range by $200 million to $2.6 to $2.8 billion, excluding acquisitions.  The spending increase will be directed toward well completions, which are now targeted to increase from the initial plan of 270 and the prior revised forecast of 350 to 450 net wells in 2016.  Drilling productivity continues to improve, and the company now expects to drill 290 net wells, 40 more than its prior forecast and 90 more than its original 2016 plans.

Delaware Basin
EOG increased its Delaware Basin net resource potential by 155 percent to 6.0 billion barrels of oil equivalent (BnBoe) in the third quarter 2016 (inclusive of the recent Yates transaction).  Delaware Basin net well locations increased by 27 percent to 6,330.  The average planned lateral length for these locations increased from 4,500 feet to over 7,000 feet. 

"With the Yates transaction, EOG's Delaware Basin position now exceeds 400,000 net acres in the core window of this world-class play," Thomas said.  "Our technical and operational advances applied to the combined assets have produced a major increase in EOG's Delaware Basin potential.   As we continue to make advances in cost management and technology, we believe our resource potential over time will continue to increase in both size and quality."

In the Delaware Basin Wolfcamp, EOG increased its net resource potential from 1.3 BnBoe to 2.9 BnBoe and net well locations from 2,130 to 2,660.  For the Delaware Basin Wolfcamp oil play, EOG's average gross reserves per well increased to 1,330 thousand barrels of crude oil equivalent (MBoe) from 750 MBoe, while average gross reserves per well increased to 1,550 MBoe from 900 MBoe in the combo portion of the play.

For the Delaware Basin Second Bone Spring, EOG increased its net resource potential from 0.5 BnBoe to 1.4 BnBoe and net well locations from 1,250 to 1,870.  Average gross reserves per well increased to 950 MBoe from 500 MBoe.

EOG also increased its Delaware Basin Leonard net resource potential from 0.6 BnBoe to 1.7 BnBoe and net well locations from 1,600 to 1,800.  Average gross reserves per well increased to 1,175 MBoe from 500 MBoe.

In the third quarter 2016, EOG completed 22 wells in the Delaware Basin Wolfcamp with an average treated lateral length of 4,800 feet per well and an average 30-day initial production rate per well of 2,350 barrels of oil equivalent per day (Boed), or 1,675 Bopd, 275 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.4 million cubic feet per day (MMcfd) of natural gas.  In the Delaware Basin Second Bone Spring, EOG completed four wells in the third quarter with an average treated lateral length of 4,600 feet per well and an average 30-day initial production rate per well of 1,240 Boed, or 940 Bopd, 120 Bpd of NGLs and 1.1 MMcfd of natural gas. 

South Texas Eagle Ford
EOG's oil-rich South Texas Eagle Ford acreage continued to deliver exceptional results in the third quarter 2016 and was once again the largest contributor to EOG's U.S. crude oil production. 

In the third quarter, EOG completed 47 wells in the Eagle Ford with an average treated lateral length of 5,700 feet per well and an average 30-day initial production rate per well of 1,825 Boed, or 1,425 Bopd, 190 Bpd of NGLs and 1.3 MMcfd of natural gas.

Rockies and the Bakken
In the third quarter, EOG completed nine wells in the Powder River Basin with an average 30-day initial production rate per well of 1,560 Boed, or 840 Bopd, 245 Bpd of NGLs and 2.8 MMcfd of natural gas.

In the DJ Basin Codell in Wyoming, EOG completed five wells in the third quarter with an average 30-day initial production rate per well of 720 Boed, or 610 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas.  

In the North Dakota Bakken, EOG completed 13 wells in the third quarter with an average 30-day initial production rate per well of 850 Boed, or 763 Bopd, 45 Bpd of NGLs and 0.3 MMcfd of natural gas.  

Hedging Activity
For the period November 1 through December 31, 2016, EOG has crude oil financial price collar contracts in place for 70,000 Bopd at an average ceiling price of $54.25 per barrel and an average floor price of $45.00 per barrel. 

For the period March 1 through November 30, 2017, EOG has natural gas financial price swap contracts in place for 30,000 million British thermal units (MMBtu) per day at a weighted average price of $3.10 per MMBtu.  

For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 213,750 MMBtu per day at an average strike price of $3.44 per MMBtu.  For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 120,000 MMBtu per day at an average strike price of $3.38 per MMBtu.

For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 171,000 MMBtu per day at an average strike price of $2.92 per MMBtu.  For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 96,000 MMBtu per day at an average strike price of $2.94 per MMBtu.   

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

Capital Structure and Asset Sales
At September 30, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 37 percent. Taking into account cash on the balance sheet of $1.1 billion at the end of the third quarter, EOG's net debt was $5.9 billion with a net debt-to-total capitalization ratio of 33 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales this year to date total $625 million.  This includes proceeds from a transaction that has already closed in the fourth quarter 2016.  Associated production of the divested assets was 80 MMcfd of natural gas, 3,400 Bopd and 4,290 Bpd of NGLs.

Conference Call November 4, 2016
EOG's third quarter 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, November 4, 2016.  To listen, 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 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 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 21 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, 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, 2015, 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.

Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902

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

 

EOG RESOURCES, INC.

Financial Report

(Unaudited; in millions, except per share data)

                       
 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

 

2016

 

2015

 

2016

 

2015

                       

Net Operating Revenues

$

2,118.5

 

$

2,172.4

 

$

5,248.6

 

$

6,960.7

Net Loss

$

(190.0)

 

$

(4,075.7)

 

$

(954.3)

 

$

(4,240.2)

Net Loss Per Share 

                     

        Basic

$

(0.35)

 

$

(7.47)

 

$

(1.74)

 

$

(7.77)

        Diluted

$

(0.35)

 

$

(7.47)

 

$

(1.74)

 

$

(7.77)

Average Number of Common Shares

                     

        Basic

 

547.8

   

545.9

   

547.3

   

545.5

        Diluted

 

547.8

   

545.9

   

547.3

   

545.5

                       
                       

Summary Income Statements

(Unaudited; in thousands, except per share data)

                       
 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

 

2016

 

2015

 

2016

 

2015

Net Operating Revenues

             

        Crude Oil and Condensate

$

1,137,717

 

$

1,181,092

 

$

2,951,118

 

$

3,894,092

        Natural Gas Liquids

 

112,439

   

95,217

   

299,401

   

311,137

        Natural Gas

 

205,293

   

281,837

   

526,779

   

843,657

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

 

5,117

   

29,239

   

(33,821)

   

56,954

        Gathering, Processing and Marketing

 

532,456

   

572,217

   

1,351,665

   

1,820,843

        Gains (Losses) on Asset Dispositions, Net

 

108,204

   

(1,185)

   

101,801

   

(5,142)

        Other, Net

 

17,278

   

14,011

   

51,650

   

39,126

               Total

 

2,118,504

   

2,172,428

   

5,248,593

   

6,960,667

Operating Expenses

                     

        Lease and Well

 

226,348

   

283,221

   

685,606

   

934,366

        Transportation Costs

 

200,862

   

203,594

   

570,787

   

641,739

        Gathering and Processing Costs

 

32,635

   

35,497

   

90,385

   

106,503

        Exploration Costs

 

25,455

   

31,344

   

85,843

   

114,548

        Dry Hole Costs

 

10,390

   

198

   

10,464

   

14,317

        Impairments 

 

177,990

   

6,307,420

   

322,321

   

6,445,375

        Marketing Costs

 

552,487

   

615,303

   

1,373,387

   

1,924,134

        Depreciation, Depletion and Amortization

 

899,511

   

722,172

   

2,690,893

   

2,544,187

        General and Administrative

 

94,397

   

90,959

   

292,633

   

257,580

        Taxes Other Than Income

 

91,909

   

105,677

   

246,068

   

334,244

               Total

 

2,311,984

   

8,395,385

   

6,368,387

   

13,316,993

                       

Operating Loss

 

(193,480)

   

(6,222,957)

   

(1,119,794)

   

(6,356,326)

                       

Other (Expense) Income, Net

 

(7,912)

   

8,607

   

(33,345)

   

7,996

                       

Loss Before Interest Expense and Income Taxes

 

(201,392)

   

(6,214,350)

   

(1,153,139)

   

(6,348,330)

                       

Interest Expense, Net

 

70,858

   

60,571

   

210,356

   

174,400

                       

Loss Before Income Taxes

 

(272,250)

   

(6,274,921)

   

(1,363,495)

   

(6,522,730)

                       

Income Tax Benefit

 

(82,250)

   

(2,199,182)

   

(409,161)

   

(2,282,511)

                       

Net Loss

$

(190,000)

 

$

(4,075,739)

 

$

(954,334)

 

$

(4,240,219)

                       

Dividends Declared per Common Share

$

0.1675

 

$

0.1675

 

$

0.5025

 

$

0.5025

 

EOG RESOURCES, INC.

 

Operating Highlights

 

(Unaudited)

 
                         
 

Three Months Ended

 

Nine Months Ended

 
 

September 30,

 

September 30,

 
 

2016

 

2015

 

2016

 

2015

 

Wellhead Volumes and Prices

       

Crude Oil and Condensate Volumes (MBbld) (A)

       

      United States

 

275.7

   

278.3

   

269.0

   

284.4

 

      Trinidad

 

0.7

   

1.0

   

0.8

   

0.9

 

      Other International (B)

 

6.2

   

0.2

   

3.0

   

0.2

 

            Total

 

282.6

   

279.5

   

272.8

   

285.5

 
                         

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

                       

      United States

$

43.66

 

$

45.93

 

$

39.53

 

$

49.94

 

      Trinidad

 

34.81

   

38.56

   

31.36

   

41.98

 

      Other International (B)

 

43.53

   

61.80

   

35.30

   

58.44

 

            Composite

 

43.63

   

45.91

   

39.46

   

49.92

 
                         

Natural Gas Liquids Volumes (MBbld) (A)

                       

      United States

 

81.9

   

77.7

   

81.9

   

76.2

 

      Other International (B)

 

-

   

0.1

   

-

   

0.1

 

            Total

 

81.9

   

77.8

   

81.9

   

76.3

 
                         

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

                       

      United States

$

14.92

 

$

13.25

 

$

13.34

 

$

14.94

 

      Other International (B)

 

-

   

8.05

   

-

   

6.05

 

            Composite

 

14.92

   

13.24

   

13.34

   

14.93

 
                         

Natural Gas Volumes (MMcfd) (A)

                       

      United States

 

791

   

889

   

813

   

895

 

      Trinidad

 

329

   

355

   

346

   

342

 

      Other International (B)

 

24

   

30

   

25

   

31

 

            Total

 

1,144

   

1,274

   

1,184

   

1,268

 
                         

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

                       

      United States

$

1.94

 

$

2.04

 

$

1.46

 

$

2.14

 

      Trinidad

 

1.86

   

2.90

   

1.88

   

3.01

 

      Other International (B)

 

3.74

   

7.18

(E)

 

3.57

   

4.63

(E)

            Composite

 

1.95

   

2.40

   

1.62

   

2.44

 
                         

Crude Oil Equivalent Volumes (MBoed) (D)

                       

      United States 

 

489.4

   

504.2

   

486.4

   

509.8

 

      Trinidad

 

55.6

   

60.2

   

58.5

   

57.9

 

      Other International (B)

 

10.2

   

5.2

   

7.2

   

5.4

 

            Total

 

555.2

   

569.6

   

552.1

   

573.1

 
                         

Total MMBoe (D)

 

51.1

   

52.4

   

151.3

   

156.5

 
 

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

(B) Other International includes EOG's United Kingdom, China and Canada operations.

(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.

(E) Includes revenue adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and year-to-date, respectively, related to a price adjustment for natural gas sales made in China from June 2012 to March 2015.

 

EOG RESOURCES, INC.

Summary Balance Sheets

(Unaudited; in thousands, except share data)

           
 

September 30,

 

December 31,

 

2016

 

2015

ASSETS

Current Assets

         

     Cash and Cash Equivalents

$

1,048,727

 

$

718,506

     Accounts Receivable, Net

 

920,189

   

930,610

     Inventories

 

429,667

   

598,935

     Assets from Price Risk Management Activities

 

2,185

   

-

     Income Taxes Receivable

 

178

   

40,704

     Deferred Income Taxes

 

137,098

   

147,812

     Other

 

199,720

   

155,677

            Total

 

2,737,764

   

2,592,244

           

Property, Plant and Equipment

         

     Oil and Gas Properties (Successful Efforts Method)

 

50,465,979

   

50,613,241

     Other Property, Plant and Equipment

 

4,013,602

   

3,986,610

            Total Property, Plant and Equipment

 

54,479,581

   

54,599,851

     Less:  Accumulated Depreciation, Depletion and Amortization

 

(31,835,196)

   

(30,389,130)

            Total Property, Plant and Equipment, Net

 

22,644,385

   

24,210,721

Other Assets

 

172,772

   

167,505

Total Assets

$

25,554,921

 

$

26,970,470

           

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         

     Accounts Payable

$

1,296,240

 

$

1,471,953

     Accrued Taxes Payable

 

143,257

   

93,618

     Dividends Payable

 

91,842

   

91,546

     Current Portion of Long-Term Debt

 

6,579

   

6,579

     Other

 

195,045

   

155,591

            Total

 

1,732,963

   

1,819,287

           
           

Long-Term Debt

 

6,979,538

   

6,648,911

Other Liabilities

 

975,763

   

971,335

Deferred Income Taxes

 

4,068,345

   

4,587,902

Commitments and Contingencies

         
           

Stockholders' Equity

         

     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and

         

        551,425,785 Shares Issued at September 30, 2016 and 550,150,823

         

        Shares Issued at December 31, 2015

 

205,514

   

205,502

     Additional Paid in Capital

 

2,992,887

   

2,923,461

     Accumulated Other Comprehensive Loss

 

(25,100)

   

(33,338)

     Retained Earnings

 

8,641,704

   

9,870,816

     Common Stock Held in Treasury, 197,181 Shares at September 30, 2016

         

        and 292,179 Shares at December 31, 2015

 

(16,693)

   

(23,406)

            Total Stockholders' Equity

 

11,798,312

   

12,943,035

Total Liabilities and Stockholders' Equity

$

25,554,921

 

$

26,970,470

 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

           
 

Nine Months Ended

 

September 30,

 

2016

 

2015

Cash Flows from Operating Activities

         

Reconciliation of Net Loss to Net Cash Provided by Operating Activities:

         

     Net Loss

$

(954,334)

 

$

(4,240,219)

     Items Not Requiring (Providing) Cash

         

            Depreciation, Depletion and Amortization

 

2,690,893

   

2,544,187

            Impairments 

 

322,321

   

6,445,375

            Stock-Based Compensation Expenses

 

97,072

   

101,926

            Deferred Income Taxes

 

(492,489)

   

(2,377,030)

            (Gains) Losses on Asset Dispositions, Net

 

(101,801)

   

5,142

            Other, Net

 

42,149

   

3,735

     Dry Hole Costs

 

10,464

   

14,317

     Mark-to-Market Commodity Derivative Contracts

         

            Total Losses (Gains)

 

33,821

   

(56,954)

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

 

(22,219)

   

661,021

     Excess Tax Benefits from Stock-Based Compensation

 

(22,071)

   

(24,219)

     Other, Net

 

7,513

   

8,904

     Changes in Components of Working Capital and Other Assets and Liabilities

         

            Accounts Receivable

 

(11,860)

   

448,311

            Inventories

 

137,563

   

27,007

            Accounts Payable

 

(201,213)

   

(1,310,211)

            Accrued Taxes Payable

 

113,996

   

77,575

            Other Assets

 

(12,526)

   

146,965

            Other Liabilities

 

36,799

   

(15,683)

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

 

(119,760)

   

519,203

Net Cash Provided by Operating Activities

 

1,554,318

   

2,979,352

           

Investing Cash Flows

         

     Additions to Oil and Gas Properties

 

(1,781,547)

   

(3,918,065)

     Additions to Other Property, Plant and Equipment

 

(60,343)

   

(252,295)

     Proceeds from Sales of Assets

 

457,665

   

144,285

     Changes in Components of Working Capital Associated with Investing Activities

 

120,614

   

(519,323)

Net Cash Used in Investing Activities

 

(1,263,611)

   

(4,545,398)

           

Financing Cash Flows

         

     Net Commercial Paper (Repayments) Borrowings

 

(259,718)

   

29,700

     Long-Term Debt Borrowings

 

991,097

   

990,225

     Long-Term Debt Repayments

 

(400,000)

   

(500,000)

     Dividends Paid

 

(276,726)

   

(274,577)

     Excess Tax Benefits from Stock-Based Compensation

 

22,071

   

24,219

     Treasury Stock Purchased

 

(55,641)

   

(43,419)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

 

14,283

   

14,967

     Debt Issuance Costs

 

(1,602)

   

(5,933)

     Repayment of Capital Lease Obligation

 

(4,746)

   

(4,599)

     Other, Net

 

(854)

   

120

Net Cash Provided by Financing Activities

 

28,164

   

230,703

           

Effect of Exchange Rate Changes on Cash

 

11,350

   

(9,181)

           

Increase (Decrease) in Cash and Cash Equivalents

 

330,221

   

(1,344,524)

Cash and Cash Equivalents at Beginning of Period

 

718,506

   

2,087,213

Cash and Cash Equivalents at End of Period

$

1,048,727

 

$

742,689

 

EOG RESOURCES, INC.

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

to Net Loss (GAAP)

(Unaudited; in thousands, except per share data)

                               
                               

The following chart adjusts the three-month and nine-month periods ended September 30, 2016 and 2015 reported Net 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 2016 and 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back impairment charges related to certain of EOG's assets in 2016 and 2015, and to add back acquisition costs related to the Yates transaction in 2016.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

                               
 

Three Months Ended 

 

Three Months Ended 

 

September 30, 2016

 

September 30, 2015

                               
     

Income

     

Diluted

     

Income

     

Diluted

 

Before

 

Tax

 

After

 

Earnings

 

Before

 

Tax

 

After

 

Earnings

 

Tax

 

Impact

 

Tax

 

per Share

 

Tax

 

Impact

 

Tax

 

per Share

Reported Net Loss (GAAP)

$   (272,250)

 

$    82,250

 

$ (190,000)

 

$     (0.35)

 

$ (6,274,921)

 

$ 2,199,182

 

$ (4,075,739)

 

$     (7.47)

Adjustments:

                             

  (Gains) Losses on Mark-to-Market Commodity 

                             

     Derivative Contracts

(5,117)

 

1,824

 

(3,293)

 

(0.01)

 

(29,239)

 

10,424

 

(18,815)

 

(0.03)

  Net Cash Received from (Payments for)

                             

     Settlements of Commodity Derivative

                             

     Contracts

(25,071)

 

8,938

 

(16,133)

 

(0.03)

 

99,879

 

(35,607)

 

64,272

 

0.12

  Add: Net (Gains) Losses on Asset Dispositions

(108,204)

 

28,802

 

(79,402)

 

(0.13)

 

1,185

 

(4,614)

 

(3,429)

 

(0.01)

  Add:  Impairments of Certain Assets

102,778

 

(36,640)

 

66,138

 

0.12

 

6,213,107

 

(2,165,884)

 

4,047,223

 

7.41

  Add:  Acquisition Costs

2,927

 

(1,043)

 

1,884

 

-

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

(32,687)

 

1,881

 

(30,806)

 

(0.05)

 

6,284,932

 

(2,195,681)

 

4,089,251

 

7.49

                               

Adjusted Net Income (Loss) (Non-GAAP)

$   (304,937)

 

$    84,131

 

$ (220,806)

 

$     (0.40)

 

$       10,011

 

$       3,501

 

$       13,512

 

$      0.02

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

547,838

             

545,920

       Diluted

           

547,838

             

545,920

                               

Average Number of Common Shares (Non-GAAP)

                             

      Basic

           

547,838

             

545,920

      Diluted

           

547,838

             

549,434

                               
                               
 

Nine Months Ended 

 

Nine Months Ended 

 

September 30, 2016

 

September 30, 2015

                               
     

Income

     

Diluted

     

Income

     

Diluted

 

Before

 

Tax

 

After

 

Earnings

 

Before

 

Tax

 

After

 

Earnings

 

Tax

 

Impact

 

Tax

 

per Share

 

Tax

 

Impact

 

Tax

 

per Share

Reported Net Loss (GAAP)

$ (1,363,495)

 

$  409,161

 

$ (954,334)

 

$     (1.74)

 

$ (6,522,730)

 

$ 2,282,511

 

$ (4,240,219)

 

$     (7.77)

Adjustments:

                             

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

33,821

 

(12,057)

 

21,764

 

0.04

 

(56,954)

 

20,304

 

(36,650)

 

(0.07)

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

(22,219)

 

7,921

 

(14,298)

 

(0.03)

 

661,021

 

(235,654)

 

425,367

 

0.79

  Add: Net (Gains) Losses on Asset Dispositions

(101,801)

 

24,635

 

(77,166)

 

(0.14)

 

5,142

 

(3,448)

 

1,694

 

-

  Less: Texas Margin Tax Rate Reduction

-

 

-

 

-

 

-

 

-

 

(19,500)

 

(19,500)

 

(0.04)

  Add:  Severance Costs

-

 

-

 

-

 

-

 

8,505

 

(3,032)

 

5,473

 

0.01

  Add:  Trinidad Tax Settlement

-

 

43,000

 

43,000

 

0.08

 

-

 

-

 

-

 

-

  Add:  Voluntary Retirement Expense

42,054

 

(14,992)

 

27,062

 

0.05

 

-

 

-

 

-

 

-

  Add:  Impairments of Certain Assets

102,778

 

(36,640)

 

66,138

 

0.12

 

6,213,107

 

(2,165,884)

 

4,047,223

 

7.41

  Add:  Acquisition Costs

2,927

 

(1,043)

 

1,884

 

-

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

57,560

 

10,824

 

68,384

 

0.12

 

6,830,821

 

(2,407,214)

 

4,423,607

 

8.10

                               

Adjusted Net Income (Loss) (Non-GAAP)

$ (1,305,935)

 

$  419,985

 

$ (885,950)

 

$     (1.62)

 

$    308,091

 

$  (124,703)

 

$    183,388

 

$      0.33

                               

Average Number of Common Shares (GAAP)

                             

    Basic

           

547,295

             

545,466

    Diluted

           

547,295

             

545,466

                               

Average Number of Common Shares (Non-GAAP)

                             

   Basic

           

547,295

             

545,466

   Diluted

           

547,295

             

549,414

 

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 nine-month periods ended September 30, 2016 and 2015 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

 

Nine Months Ended

   

September 30,

 

September 30,

   

2016

 

2015

 

2016

 

2015

                         

Net Cash Provided by Operating Activities (GAAP)

$

759,581

 

$

1,131,432

 

$

1,554,318

 

$

2,979,352

                         

Adjustments:

                       

Exploration Costs (excluding Stock-Based Compensation Expenses) 

 

21,384

   

25,286

   

70,268

   

95,253

Excess Tax Benefits from Stock-Based Compensation

   

10,260

   

7,826

   

22,071

   

24,219

Changes in Components of Working Capital and Other Assets

                       

and Liabilities

                       

Accounts Receivable

   

(10,712)

   

(150,128)

   

11,860

   

(448,311)

Inventories

   

(41,750)

   

10,602

   

(137,563)

   

(27,007)

Accounts Payable

   

(2,145)

   

310,567

   

201,213

   

1,310,211

Accrued Taxes Payable

   

(20,676)

   

(13,451)

   

(113,996)

   

(77,575)

Other Assets

   

(21,063)

   

(70,851)

   

12,526

   

(146,965)

Other Liabilities

   

(35,234)

   

(33,165)

   

(36,799)

   

15,683

Changes in Components of Working Capital Associated with 

                       

Investing and Financing Activities

   

65,307

   

(349,401)

   

119,760

   

(519,203)

 

Discretionary Cash Flow (Non-GAAP)

 

$

724,952

 

$

868,717

 

$

1,703,658

 

$

3,205,657

                         

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease

   

-17%

         

-47%

     

 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, 

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

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

 (Non-GAAP) to Net Loss (GAAP)

(Unaudited; in thousands)

                       

The following chart adjusts the three-month and nine-month periods ended September 30, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes, 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.  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, Income Taxes (Income Tax 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

 

Nine Months Ended

 

September 30,

 

September 30,

 

2016

 

2015

 

2016

 

2015

                       

Net Loss (GAAP)

$

(190,000)

 

$

(4,075,739)

 

$

(954,334)

 

$

(4,240,219)

                       

Adjustments:

                     

     Interest Expense, Net

 

70,858

   

60,571

   

210,356

   

174,400

     Income Tax Benefit

 

(82,250)

   

(2,199,182)

   

(409,161)

   

(2,282,511)

     Depreciation, Depletion and Amortization

 

899,511

   

722,172

   

2,690,893

   

2,544,187

     Exploration Costs

 

25,455

   

31,344

   

85,843

   

114,548

     Dry Hole Costs

 

10,390

   

198

   

10,464

   

14,317

     Impairments 

 

177,990

   

6,307,420

   

322,321

   

6,445,375

             EBITDAX (Non-GAAP)

 

911,954

   

846,784

   

1,956,382

   

2,770,097

     Total (Gains) Losses on MTM Commodity Derivative Contracts  

 

(5,117)

   

(29,239)

   

33,821

   

(56,954)

     Net Cash Received from (Payments for) Settlements of Commodity

                     

     Derivative Contracts

 

(25,071)

   

99,879

   

(22,219)

   

661,021

     (Gains) Losses on Asset Dispositions, Net

 

(108,204)

   

1,185

   

(101,801)

   

5,142

                       

Adjusted EBITDAX (Non-GAAP)

$

773,562

 

$

918,609

 

$

1,866,183

 

$

3,379,306

                       

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

 

-16%

         

-45%

     

 

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

 

September 30,

 

December 31,

 

2016

 

2015

           

Total Stockholders' Equity - (a)

$

11,798

 

$

12,943

           

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

 

6,986

   

6,655

Less: Cash 

 

(1,049)

   

(719)

Net Debt (Non-GAAP) - (c)

 

5,937

   

5,936

           

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

$

18,784

 

$

19,598

           

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

$

17,735

 

$

18,879

           

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

 

37%

   

34%

           

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

 

33%

   

31%

 

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.  Presented below is a comprehensive summary of EOG's crude oil price swap contracts through November 3, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl.  

                       
                       

Crude Oil Price Swap Contracts

                 

Weighted

                 

Volume

 

Average Price

                 

(Bbld) 

 

($/Bbl) 

2016

                   

April 12, 2016 through April 30, 2016 (closed)

           

90,000

 

$               42.30

May 1, 2016 through June 30, 2016 (closed)

           

128,000

 

42.56

                       
                       

EOG has entered into crude oil collar contracts, which establish ceiling and floor prices for the sale of notional volumes of crude oil as specified in the collar contracts.  The collars require that EOG pay the difference between the ceiling price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price) in the event the Index Price is above the ceiling price.  The collars grant EOG the right to receive the difference between the floor price and the Index Price in the event the Index Price is below the floor price.  Presented below is a comprehensive summary of EOG's crude oil collar contracts through November 3, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl.  

                       
                       

Crude Oil Collar Contracts

                 

Weighted Average Price ($/Bbl)

             

 Volume (Bbld) 

 

Ceiling Price

 

Floor Price

2016

                   

September 1, 2016 through October 31, 2016 (closed)

     

70,000

 

$             54.25

 

$               45.00

November 1, 2016 through December 31, 2016

       

70,000

 

54.25

 

45.00

                       
                       

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through November 3, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

                       
                       

Natural Gas Price Swap Contracts

                     

Weighted

                 

Volume

 

Average Price

                 

(MMBtud)

 

($/MMBtu)

2016

                   

March 1, 2016 through August 31, 2016 (closed)

           

60,000

 

$                 2.49

                       

2017

                   

March 1, 2017 through November 30, 2017

           

30,000

 

$                 3.10

                       
                       

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 November 3, 2016, 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)

2016

                   

September 2016 (closed)

   

56,250

 

$                   3.46

 

-

 

$                       -

October 1, 2016 through November 30, 2016 (closed)

   

106,250

 

3.48

 

-

 

-

                       

2017

                   

March 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

                       
                       

Definitions

                   

Bbld

Barrels per day

                 

$/Bbl

Dollars per barrel

                 

MMBtud 

Million British thermal units per day

                 

$/MMBtu

Dollars per million British thermal units

                 

NYMEX

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

 
 

Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

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

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical

 

Payback ~12 Months on 100% Direct ATROR Wells

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

 
 

Return on Equity / Return on Capital Employed 

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

 

EOG RESOURCES, INC.

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

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

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

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

                       
   

2015

   

2014

   

2013

   

2012

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

                     
                       

Net Interest Expense (GAAP)

$

237

 

$

201

 

$

235

     

Tax Benefit Imputed (based on 35%) 

 

(83)

   

(70)

   

(82)

     

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

$

154

 

$

131

 

$

153

     
                       

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

$

(4,525)

 

$

2,915

 

$

2,197

     

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

4,559

 (a) 

 

(199)

 (b) 

 

49

 (c) 

   

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

$

34

 

$

2,716

 

$

2,246

     
                       

Total Stockholders' Equity - (d)   

$

12,943

 

$

17,713

 

$

15,418

 

$

13,285

                       

Average Total Stockholders' Equity * - (e)   

$

15,328

 

$

16,566

 

$

14,352

     
                       

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

$

6,660

 

$

5,910

 

$

5,913

 

$

6,312

Less: Cash                                                       

 

(719)

   

(2,087)

   

(1,318)

   

(876)

Net Debt (Non-GAAP) - (g) 

$

5,941

 

$

3,823

 

$

4,595

 

$

5,436

                       

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

$

19,603

 

$

23,623

 

$

21,331

 

$

19,597

                       

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

$

18,884

 

$

21,536

 

$

20,013

 

$

18,721

                       

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

$

20,210

 

$

20,775

 

$

19,367

     
                       

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

 

-21.6%

   

14.7%

   

12.1%

     
                       

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

 

0.9%

   

13.7%

   

12.4%

     
                       

Return on Equity (ROE) (Non-GAAP)

                     
                       

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

 

-29.5%

   

17.6%

   

15.3%

     
                       

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

 

0.2%

   

16.4%

   

15.6%

     
                       

* 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 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

     
                       

(b) 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)

     
                       

(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2013:

                 
   

Year Ended December 31, 2013

     
   

 Before 

   

 Income Tax  

   

 After 

     
   

 Tax 

   

 Impact 

   

 Tax 

     

Adjustments:

                     

    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

283

 

$

(101)

 

$

182

     

    Add:   Impairments of Certain Assets

 

7

   

(3)

   

4

     

    Less:  Net Gains on Asset Dispositions

 

(198)

   

61

   

(137)

     

Total

$

92

 

$

(43)

 

$

49

     

 

EOG RESOURCES, INC.

Fourth Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing

                       

     (a)  Fourth Quarter and Full Year 2016 Forecast

                     
                       

The forecast items for the fourth quarter and full year 2016 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)

     
   

4Q 2016

   

Full Year 2016

Daily Production

                     

     Crude Oil and Condensate Volumes (MBbld)

                     

          United States

 

290.0

-

 

300.0

   

274.3

-

 

276.8

          Trinidad

 

0.4

-

 

0.8

   

0.7

-

 

0.8

          Other International

 

5.0

-

 

9.0

   

3.5

-

 

4.5

               Total

 

295.4

-

 

309.8

   

278.5

-

 

282.1

                       

     Natural Gas Liquids Volumes (MBbld)

                     

               Total

 

79.0

-

 

83.0

   

81.1

-

 

82.2

                       

     Natural Gas Volumes (MMcfd)

                     

          United States

 

810

-

 

840

   

813

-

 

820

          Trinidad

 

300

-

 

330

   

335

-

 

342

          Other International

 

20

-

 

24

   

24

-

 

25

               Total

 

1,130

-

 

1,194

   

1,172

-

 

1,187

                       

     Crude Oil Equivalent Volumes (MBoed)  

                     

          United States

 

504.0

-

 

523.0

   

490.9

-

 

495.7

          Trinidad

 

50.4

-

 

55.8

   

56.5

-

 

57.8

          Other International

 

8.3

-

 

13.0

   

7.5

-

 

8.7

               Total

 

562.7

-

 

591.8

   

554.9

-

 

562.2

                       

Operating Costs

                     

     Unit Costs ($/Boe)

                     

          Lease and Well

$

4.40

-

$

4.90

 

$

4.50

-

$

4.66

          Transportation Costs

$

3.75

-

$

4.25

 

$

3.77

-

$

3.90

          Depreciation, Depletion and Amortization

$

17.70

-

$

18.10

 

$

17.77

-

$

17.87

                       

Expenses ($MM)

                     

     Exploration, Dry Hole and Impairment

$

105

-

$

135

 

$

421

-

$

451

     General and Administrative

$

90

-

$

100

 

$

338

-

$

348

     Gathering and Processing 

$

29

-

$

31

 

$

119

-

$

121

     Capitalized Interest

$

33

-

$

37

 

$

58

-

$

62

     Net Interest

$

41

-

$

44

 

$

251

-

$

254

                       

Taxes Other Than Income (% of Wellhead Revenue)

 

5.9%

-

 

6.3%

   

6.3%

-

 

6.5%

                       

Income Taxes

                     

     Effective Rate 

 

28%

-

 

33%

   

28%

-

 

33%

     Current Taxes ($MM)

$

25

-

$

40

 

$

108

-

$

123

                       

Capital Expenditures (Excluding Acquisitions, $MM)

                     

     Exploration and Development, Excluding Facilities

           

$

2,200

-

$

2,300

     Exploration and Development Facilities

           

$

325

-

$

375

     Gathering, Processing and Other

           

$

75

-

$

125

                       

Pricing - (Refer to Benchmark Commodity Pricing in text)

                     

     Crude Oil and Condensate ($/Bbl)

                     

          Differentials

                     

               United States - above (below) WTI

$

(2.40)

-

$

(1.40)

 

$

(1.90)

-

$

(1.63)

               Trinidad - above (below) WTI

$

(10.50)

-

$

(9.50)

 

$

(10.31)

-

$

(10.10)

               Other International - above (below) WTI

$

(6.00)

-

$

(4.00)

 

$

(4.00)

-

$

(3.50)

                       

     Natural Gas Liquids

                     

          Realizations as % of WTI

 

29%

-

 

33%

   

31%

-

 

32%

                       

     Natural Gas ($/Mcf)

                     

          Differentials

                     

               United States - above (below) NYMEX Henry Hub

$

(1.05)

-

$

(0.65)

 

$

(0.86)

-

$

(0.76)

                       

          Realizations

                     

               Trinidad

$

1.70

-

$

2.10

 

$

1.83

-

$

1.93

               Other International

$

3.45

-

$

3.95

 

$

3.54

-

$

3.66

                       

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      New York Mercantile Exchange

                     

WTI            West Texas Intermediate

                     

 

SOURCE EOG Resources, Inc.

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