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EOG Resources Reports Fourth Quarter and Full Year 2016 Results and Announces 2017 Capital Program

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HOUSTON, Feb. 27, 2017 /PRNewswire/ -- 

  • Exceeds High-end of Fourth Quarter and Full Year 2016 Crude Oil Production Targets
  • Beats Fourth Quarter and Full Year 2016 Targets for Lease and Well, Transportation and DD&A Expenses
  • Achieves Record Capital Efficiency Gains in 2016
  • Replaces 163 Percent of 2016 Production at Low Finding Cost of $5.22/Boe (Excluding Price Revisions) and Increases Total Net Proved Reserves by 1.4 Percent in 2016
  • Targets 18 Percent Crude Oil Production Growth for 2017 within Cash Flow at Flat $50 Oil
  • Forecasts Flat to Lower Well Costs in 2017

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a fourth quarter 2016 net loss of $142.4 million, or $0.25 per share. This compares to a fourth quarter 2015 net loss of $284.3 million, or $0.52 per share.  For full year 2016, EOG reported a net loss of $1.1 billion, or $1.98 per share, compared to a net loss of $4.5 billion, or $8.29 per share, for the full year 2015. 

Adjusted non-GAAP net loss for the fourth quarter 2016 was $6.7 million, or $0.01 per share, compared to adjusted non-GAAP net loss of $149.5 million, or $0.27 per share, for the same prior year period.  Adjusted non-GAAP net loss for the full year 2016 was $892.6 million, or $1.61 per share, compared to adjusted non-GAAP net income of $33.9 million, or $0.06 per share, for the full year 2015.  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.

Higher crude oil, NGL and natural gas prices, significant well productivity improvements, and lease and well cost reductions resulted in increases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2016 compared to the fourth quarter 2015.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights
Tremendous capital efficiency improvements in 2016 offset the impact of a significant reduction in capital expenditures resulting from low oil prices.  2016 total company crude oil and condensate volumes declined less than one percent to 282,500 barrels of oil per day (Bopd) while exploration and development expenditures (excluding acquisitions) decreased 42 percent compared to 2015.  Increased development activity and significant well productivity improvements drove substantial volume increases in the Delaware Basin, with additional growth from the Powder River and DJ Basins.  These contributions were offset by volume declines in the Bakken and Eagle Ford resulting from lower activity levels.  Natural gas liquids volumes grew 6 percent while natural gas volumes decreased 7 percent primarily due to natural decline and the sale of the company's Barnett and Haynesville Shale dry gas assets.  Compared to the same prior year period, lease and well expenses decreased 20 percent and transportation expenses decreased 8 percent, both on a per-unit basis.  Total operating costs, which includes lease and well, transportation, gathering and processing, and general and administrative expenses, were down 15 percent year over year.

"EOG achieved near company-record returns on new capital in 2016 in spite of the lowest crude oil prices in 13 years," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "Through continued improvements in well productivity, cost reductions and expanded resource potential, EOG is positioned to excel as crude oil prices continue to recover.  More than ever, EOG continues to lead the industry through its innovative technology and disciplined culture."

2017 Capital Plan
EOG's 2017 plan is designed to maximize returns and grow crude oil volumes while maintaining a strong balance sheet through disciplined spending.  EOG expects to grow total company crude oil volumes by 18 percent, assuming investment and dividend payments within cash flow at a $50 average oil price.

Capital expenditures for 2017 are expected to range from $3.7 to $4.1 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions.  The company expects to complete approximately 480 net wells in 2017, compared to 445 net wells in 2016.  EOG anticipates flat to lower completed well costs in 2017 versus 2016 levels as continued efficiencies and service contract expirations are expected to offset potential cost increases.

Capital will be allocated primarily to EOG's highest rate-of-return oil assets in the Eagle Ford, Delaware Basin, Rockies and the Bakken.  After reducing the drilled uncompleted well inventory to a normal operating level in 2016, the company will increase its focus on its 6,000 remaining premium drilling locations.  EOG is capable of delivering very strong rates of return in the current commodity price environment through premium drilling combined with the company's expectations that well costs will remain flat or lower in 2017.  Premium inventory includes wells with a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices.

"EOG's goal during the last two years was to exit the industry downturn in better shape than when we entered it," Thomas said.  "We clearly accomplished that goal with spectacular improvements in all facets of the business.  We made major technology advances in our proprietary well targeting, completion designs, drilling practices and production operations.  EOG is now set to resume strong oil growth within cash flow." 

Delaware Basin
In the fourth quarter 2016, EOG continued active development of its world-class position in the Delaware Basin.  EOG integrated the assets acquired in the Yates transaction and further optimized its proprietary well targeting methods across its expanded position of 416,000 net acres.

EOG completed 17 wells in the Delaware Basin Wolfcamp in the fourth quarter with an average treated lateral length of 4,900 feet per well and average 30-day initial production rates per well of 2,405 barrels of oil equivalent per day (Boed), or 1,595 Bopd, 365 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.7 million cubic feet per day (MMcfd) of natural gas.  In Lea County, N.M., EOG completed the Endurance 36 State Com #705H and #706H with an average treated lateral length of 7,000 feet per well and average 30-day initial production rates per well of 2,495 Bopd, 505 Bpd of NGLs and 3.7 MMcfd of natural gas.

In the Delaware Basin Bone Spring, EOG completed three wells in the fourth quarter with an average treated lateral length of 4,400 feet per well and average 30-day initial production rates per well of 1,680 Boed, or 1,280 Bopd, 180 Bpd of NGLs and 1.3 MMcfd of natural gas.  In Lea County, N.M., EOG completed the Della 29 Fed Com #602H with a treated lateral of 4,500 feet and 30-day initial production rates of 1,905 Bopd, 225 Bpd of NGLs and 1.7 MMcfd of natural gas.  This well is six miles north of EOG's next closest Bone Spring well.

In the Delaware Basin Leonard, EOG completed eight wells in the fourth quarter with an average treated lateral length of 4,600 feet per well and average 30-day initial production rates per well of 1,745 Boed, or 985 Bopd, 345 Bpd of NGLs and 2.5 MMcfd of natural gas.  In Lea County, N.M., EOG completed the Leghorn 32 State #201H with a treated lateral of 4,500 feet and 30-day initial production rates of 2,550 Bopd, 480 Bpd of NGLs and 3.6 MMcfd of natural gas.  This well is 12 miles north of EOG's next closest Leonard well.

South Texas Eagle Ford
EOG continued to achieve strong well results and efficiencies in the South Texas Eagle Ford in the fourth quarter 2016.  For the full year 2016, crude oil production declined just 8 percent year-over-year, despite a 28 percent reduction in the number of well completions.

In the fourth quarter, EOG completed 75 wells in the Eagle Ford with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 1,190 Boed, or 990 Bopd, 85 Bpd of NGLs and 0.7 MMcfd of natural gas.  The fourth quarter 2016 completions in the Eagle Ford included 45 wells that were drilled prior to 2016.

South Texas Austin Chalk
EOG continued to test its position in the South Texas Austin Chalk, which lies above the South Texas Eagle Ford.  In the fourth quarter, EOG completed nine wells in the Austin Chalk with an average treated lateral length of 4,100 feet per well and average 30-day initial production rates per well of 1,975 Boed, or 1,475 Bopd, 220 Bpd of NGLs and 1.7 MMcfd of natural gas.

Rockies and the Bakken
During the fourth quarter, EOG significantly reduced its inventory of drilled uncompleted wells in the Rockies and the Bakken.       

In the Powder River Basin, EOG completed three wells in the fourth quarter with average 30-day initial production rates per well of 2,155 Boed, or 1,810 Bopd, 135 Bpd of NGLs and 1.3 MMcfd of natural gas. 

In the North Dakota Bakken, EOG completed 34 wells in the fourth quarter with average 30-day initial production rates per well of 820 Boed, or 715 Bopd, 55 Bpd of NGLs and 0.3 MMcfd of natural gas.  The fourth quarter 2016 completions in the Bakken included 31 wells that were drilled prior to 2016.

Reserves
At year-end 2016, total company net proved reserves were 2,147 million barrels of oil equivalent (MMBoe), comprised of 55 percent crude oil and condensate, 19 percent NGLs and 26 percent natural gas.  Net proved reserve additions from all sources excluding revisions due to price replaced 163 percent of EOG's 2016 production at a finding and development cost of $5.22 per barrel of oil equivalent.  Revisions due to price reduced net proved reserves by 101 MMBoe and asset divestitures decreased net proved reserves by 168 MMBoe.  Total company net proved reserves increased 1.4 percent in 2016 as proved reserve additions from drilling activities and revisions other than price offset the impact of asset divestitures and declines in commodity prices.  (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)

For the 29th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.

Hedging Activity
For the period January 1 through June 30, 2017, EOG has crude oil financial price swap contracts in place for 35,000 Bopd at a weighted average price of $50.04 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, 2018, EOG has natural gas financial price swap contracts in place for 35,000 MMBtu per day at a weighted average price of $3.00 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.   

For the period March 1 through November 30, 2017, EOG has natural gas collar contracts for 80,000 MMBtu per day at an average ceiling price of $3.69 per MMBtu and an average floor price of $3.20 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 December 31, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 33 percent. Considering cash on the balance sheet of $1.6 billion at the end of the fourth quarter, EOG's net debt was $5.4 billion with 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 for the full year 2016 totaled $1.1 billion, which includes $662 million of proceeds from sales made during the fourth quarter 2016.  Associated production of the divested assets in 2016 at the time of each respective sale was an aggregate 220 MMcfd of natural gas, 4,000 Bopd and 8,800 Bpd of NGLs (this was partially offset by the full year impact of acquired production from the Yates transaction of 2,900 Bopd, 150 Bpd of NGLs and 20 MMcfd of natural gas).

Dividend
The board of directors declared a dividend of $0.1675 per share on EOG's Common Stock, payable April 28, 2017, to stockholders of record as of April 13, 2017.  The indicated annual rate is $0.67 per share.

Conference Call February 28, 2017
EOG's fourth quarter and full year 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Tuesday, February 28, 2017.  To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.  

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

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

 

Cedric W. Burgher

 

(713) 571-4658

 

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

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2016

 

2015

 

2016

 

2015

                       

Net Operating Revenues

$

2,402.0

 

$

1,796.8

 

$

7,650.6

 

$

8,757.4

Net Loss

$

(142.4)

 

$

(284.3)

 

$

(1,096.7)

 

$

(4,524.5)

Net Loss Per Share 

                     

        Basic

$

(0.25)

 

$

(0.52)

 

$

(1.98)

 

$

(8.29)

        Diluted

$

(0.25)

 

$

(0.52)

 

$

(1.98)

 

$

(8.29)

Average Number of Common Shares

                     

        Basic

 

567.3

   

546.4

   

553.4

   

545.7

        Diluted

 

567.3

   

546.4

   

553.4

   

545.7

                       
                       

Summary Income Statements

(Unaudited; in thousands, except per share data)

                       
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2016

 

2015

 

2016

 

2015

Net Operating Revenues

             

        Crude Oil and Condensate

$

1,366,223

 

$

1,040,470

 

$

4,317,341

 

$

4,934,562

        Natural Gas Liquids

 

137,849

   

96,521

   

437,250

   

407,658

        Natural Gas

 

215,373

   

217,381

   

742,152

   

1,061,038

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

 

(65,787)

   

4,970

   

(99,608)

   

61,924

        Gathering, Processing and Marketing

 

614,594

   

432,292

   

1,966,259

   

2,253,135

        Gains (Losses) on Asset Dispositions, Net

 

104,034

   

(3,656)

   

205,835

   

(8,798)

        Other, Net

 

29,753

   

8,783

   

81,403

   

47,909

               Total

 

2,402,039

   

1,796,761

   

7,650,632

   

8,757,428

Operating Expenses

                     

        Lease and Well

 

241,846

   

247,916

   

927,452

   

1,182,282

        Transportation Costs

 

193,319

   

207,580

   

764,106

   

849,319

        Gathering and Processing Costs

 

32,516

   

39,653

   

122,901

   

146,156

        Exploration Costs

 

39,110

   

34,946

   

124,953

   

149,494

        Dry Hole Costs

 

193

   

429

   

10,657

   

14,746

        Impairments 

 

297,946

   

168,171

   

620,267

   

6,613,546

        Marketing Costs

 

634,248

   

461,848

   

2,007,635

   

2,385,982

        Depreciation, Depletion and Amortization

 

862,524

   

769,457

   

3,553,417

   

3,313,644

        General and Administrative

 

102,182

   

109,014

   

394,815

   

366,594

        Taxes Other Than Income

 

103,642

   

87,500

   

349,710

   

421,744

               Total

 

2,507,526

   

2,126,514

   

8,875,913

   

15,443,507

                       

Operating Loss

 

(105,487)

   

(329,753)

   

(1,225,281)

   

(6,686,079)

                       

Other (Expense) Income, Net

 

(17,198)

   

(6,080)

   

(50,543)

   

1,916

                       

Loss Before Interest Expense and Income Taxes

 

(122,685)

   

(335,833)

   

(1,275,824)

   

(6,684,163)

                       

Interest Expense, Net

 

71,325

   

62,993

   

281,681

   

237,393

                       

Loss Before Income Taxes

 

(194,010)

   

(398,826)

   

(1,557,505)

   

(6,921,556)

                       

Income Tax Benefit

 

(51,658)

   

(114,530)

   

(460,819)

   

(2,397,041)

                       

Net Loss

$

(142,352)

 

$

(284,296)

 

$

(1,096,686)

 

$

(4,524,515)

                       

Dividends Declared per Common Share

$

0.1675

 

$

0.1675

 

$

0.6700

 

$

0.6700

 

 

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)

                       
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2016

 

2015

 

2016

 

2015

Wellhead Volumes and Prices

     

Crude Oil and Condensate Volumes (MBbld) (A)

     

      United States

 

306.0

   

279.9

   

278.3

   

283.3

      Trinidad

 

0.9

   

0.9

   

0.8

   

0.9

      Other International (B)

 

4.8

   

0.2

   

3.4

   

0.2

            Total

 

311.7

   

281.0

   

282.5

   

284.4

                       

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

                     

      United States

$

47.93

 

$

40.34

 

$

41.84

 

$

47.55

      Trinidad

 

40.04

   

32.38

   

33.76

   

39.51

      Other International (B)

 

38.96

   

53.28

   

36.72

   

57.32

            Composite

 

47.76

   

40.32

   

41.76

   

47.53

                       

Natural Gas Liquids Volumes (MBbld) (A)

                     

      United States

 

80.9

   

79.1

   

81.6

   

76.9

      Other International (B)

 

-

   

-

   

-

   

0.1

            Total

 

80.9

   

79.1

   

81.6

   

77.0

                       

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

                     

      United States

$

18.51

 

$

13.25

 

$

14.63

 

$

14.50

      Other International (B)

 

-

   

-

   

-

   

4.61

            Composite

 

18.51

   

13.25

   

14.63

   

14.49

                       

Natural Gas Volumes (MMcfd) (A)

                     

      United States

 

800

   

860

   

810

   

886

      Trinidad

 

323

   

370

   

340

   

349

      Other International (B)

 

22

   

27

   

25

   

30

            Total

 

1,145

   

1,257

   

1,175

   

1,265

                       

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

                     

      United States

$

2.05

 

$

1.44

 

$

1.60

 

$

1.97

      Trinidad

 

1.89

   

2.57

   

1.88

   

2.89

      Other International (B)

 

3.85

   

6.51

   

3.64

   

5.05

            Composite

 

2.04

   

1.88

   

1.73

   

2.30

                       

Crude Oil Equivalent Volumes (MBoed) (D)

                     

      United States 

 

520.3

   

502.2

   

494.9

   

507.9

      Trinidad

 

54.6

   

62.7

   

57.5

   

59.1

      Other International (B)

 

8.6

   

4.6

   

7.6

   

5.2

            Total

 

583.5

   

569.5

   

560.0

   

572.2

                       

Total MMBoe (D)

 

53.7

   

52.4

   

205.0

   

208.9

                       

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

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

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

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

 

EOG RESOURCES, INC.

Summary Balance Sheets

(Unaudited; in thousands, except share data)

           
 

December 31,

 

December 31,

 

2016

 

2015

ASSETS

Current Assets

         

     Cash and Cash Equivalents

$

1,599,895

 

$

718,506

     Accounts Receivable, Net

 

1,216,320

   

930,610

     Inventories

 

350,017

   

598,935

     Income Taxes Receivable

 

12,305

   

40,704

     Deferred Income Taxes

 

169,387

   

147,812

     Other

 

206,679

   

155,677

            Total

 

3,554,603

   

2,592,244

           

Property, Plant and Equipment

         

     Oil and Gas Properties (Successful Efforts Method)

 

49,592,091

   

50,613,241

     Other Property, Plant and Equipment

 

4,008,564

   

3,986,610

            Total Property, Plant and Equipment

 

53,600,655

   

54,599,851

     Less:  Accumulated Depreciation, Depletion and Amortization

 

(27,893,577)

   

(30,389,130)

            Total Property, Plant and Equipment, Net

 

25,707,078

   

24,210,721

Other Assets

 

197,752

   

167,505

Total Assets

$

29,459,433

 

$

26,970,470

           

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities

         

     Accounts Payable

$

1,511,826

 

$

1,471,953

     Accrued Taxes Payable

 

118,411

   

93,618

     Dividends Payable

 

96,120

   

91,546

     Liabilities from Price Risk Management Activities

 

61,817

   

-

     Current Portion of Long-Term Debt

 

6,579

   

6,579

     Other

 

232,538

   

155,591

            Total

 

2,027,291

   

1,819,287

           
           

Long-Term Debt

 

6,979,779

   

6,648,911

Other Liabilities

 

1,282,142

   

971,335

Deferred Income Taxes

 

5,188,640

   

4,587,902

Commitments and Contingencies

         
           

Stockholders' Equity

         

     Common Stock, $0.01 Par, 640,000,000 Shares Authorized and
        576,950,272 Shares and 550,150,823 Shares Issued at December 31,
        2016 and 2015, respectively

 

205,770

   

205,502

     Additional Paid in Capital

 

5,420,385

   

2,923,461

     Accumulated Other Comprehensive Loss

 

(19,010)

   

(33,338)

     Retained Earnings

 

8,398,118

   

9,870,816

     Common Stock Held in Treasury, 250,155 Shares and 292,179 Shares at
        December 31, 2016 and 2015, respectively

 

(23,682)

   

(23,406)

            Total Stockholders' Equity

 

13,981,581

   

12,943,035

Total Liabilities and Stockholders' Equity

$

29,459,433

 

$

26,970,470

 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)

           
 

Twelve Months Ended

 

December 31,

 

2016

 

2015

Cash Flows from Operating Activities

         

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

         

     Net Loss

$

(1,096,686)

 

$

(4,524,515)

     Items Not Requiring (Providing) Cash

         

            Depreciation, Depletion and Amortization

 

3,553,417

   

3,313,644

            Impairments 

 

620,267

   

6,613,546

            Stock-Based Compensation Expenses

 

128,090

   

130,577

            Deferred Income Taxes

 

(515,206)

   

(2,482,307)

            (Gains) Losses on Asset Dispositions, Net

 

(205,835)

   

8,798

            Other, Net

 

61,690

   

11,896

     Dry Hole Costs

 

10,657

   

14,746

     Mark-to-Market Commodity Derivative Contracts

         

            Total Losses (Gains)

 

99,608

   

(61,924)

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

 

(22,219)

   

730,114

     Excess Tax Benefits from Stock-Based Compensation

 

(29,357)

   

(26,058)

     Other, Net

 

10,971

   

12,532

     Changes in Components of Working Capital and Other Assets and Liabilities

         

            Accounts Receivable

 

(232,799)

   

641,412

            Inventories

 

170,694

   

58,450

            Accounts Payable

 

(74,048)

   

(1,409,197)

            Accrued Taxes Payable

 

92,782

   

11,798

            Other Assets

 

(40,636)

   

118,143

            Other Liabilities

 

(16,225)

   

(66,257)

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

 

(156,102)

   

499,767

Net Cash Provided by Operating Activities

 

2,359,063

   

3,595,165

           

Investing Cash Flows

         

     Additions to Oil and Gas Properties

 

(2,489,756)

   

(4,725,150)

     Additions to Other Property, Plant and Equipment

 

(93,039)

   

(288,013)

     Proceeds from Sales of Assets

 

1,119,215

   

192,807

     Net Cash Received from Yates Acquisition

 

54,534

   

-

     Changes in Components of Working Capital Associated with Investing Activities

 

156,102

   

(499,900)

Net Cash Used in Investing Activities

 

(1,252,944)

   

(5,320,256)

           

Financing Cash Flows

         

     Net Commercial Paper (Repayments) Borrowings

 

(259,718)

   

259,718

     Long-Term Debt Borrowings

 

991,097

   

990,225

     Long-Term Debt Repayments

 

(563,829)

   

(500,000)

     Dividends Paid

 

(372,845)

   

(367,005)

     Excess Tax Benefits from Stock-Based Compensation

 

29,357

   

26,058

     Treasury Stock Purchased

 

(82,125)

   

(48,791)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

 

23,296

   

22,690

     Debt Issuance Costs

 

(1,602)

   

(5,951)

     Repayment of Capital Lease Obligation

 

(6,353)

   

(6,156)

     Other, Net

 

-

   

133

Net Cash (Used in) Provided by Financing Activities

 

(242,722)

   

370,921

           

Effect of Exchange Rate Changes on Cash

 

17,992

   

(14,537)

           

Increase (Decrease) in Cash and Cash Equivalents

 

881,389

   

(1,368,707)

Cash and Cash Equivalents at Beginning of Period

 

718,506

   

2,087,213

Cash and Cash Equivalents at End of Period

$

1,599,895

 

$

718,506

           

 

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 twelve-month periods ended December 31, 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 add back impairment charges related to certain of EOG's assets in 2016 and 2015, to add back an early leasehold termination payment as the result of a legal settlement in 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, and to add back acquisition costs and state apportionment change 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 items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

                               
 

Three Months Ended 

 

Three Months Ended 

 

December 31, 2016

 

December 31, 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)

$   (194,010)

 

$  51,658

 

$   (142,352)

 

$     (0.25)

 

$   (398,826)

 

$   114,530

 

$   (284,296)

 

$     (0.52)

Adjustments:

                             

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

65,787

 

(23,583)

 

42,204

 

0.07

 

(4,970)

 

1,772

 

(3,198)

 

(0.01)

Net Cash Received from Settlements of
     Commodity Derivative Contracts

-

 

29

 

29

 

-

 

69,093

 

(24,632)

 

44,461

 

0.08

Add: Net (Gains) Losses on Asset Dispositions

(104,034)

 

36,856

 

(67,178)

 

(0.12)

 

3,656

 

(735)

 

2,921

 

0.01

Add:  Impairments

217,839

 

(76,728)

 

141,111

 

0.25

 

94,484

 

(16,335)

 

78,149

 

0.15

Add:  Legal Settlement - Early Leasehold Termination

-

 

-

 

-

 

-

 

19,355

 

(6,900)

 

12,455

 

0.02

Add:  Voluntary Retirement Expense

-

 

(57)

 

(57)

 

-

 

-

 

-

 

-

 

-

Add:  Acquisition - State Apportionment Change

-

 

16,424

 

16,424

 

0.03

 

-

 

-

 

-

 

-

Add:  Acquisition Costs

2,173

 

955

 

3,128

 

0.01

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

181,765

 

(46,104)

 

135,661

 

0.24

 

181,618

 

(46,830)

 

134,788

 

0.25

                               

Adjusted Net Income (Loss) (Non-GAAP)

$     (12,245)

 

$    5,554

 

$      (6,691)

 

$     (0.01)

 

$   (217,208)

 

$     67,700

 

$   (149,508)

 

$     (0.27)

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

567,337

             

546,432

       Diluted

           

567,337

             

546,432

                               

Average Number of Common Shares (Non-GAAP)

                             

      Basic

           

567,337

             

546,432

      Diluted

           

567,337

             

546,432

                               
                               
 

Twelve Months Ended 

 

Twelve Months Ended 

 

December 31, 2016

 

December 31, 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)

$(1,557,505)

 

$460,819

 

$(1,096,686)

 

$     (1.98)

 

$(6,921,556)

 

$2,397,041

 

$(4,524,515)

 

$     (8.29)

Adjustments:

                             

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

99,608

 

(35,640)

 

63,968

 

0.12

 

(61,924)

 

22,076

 

(39,848)

 

(0.07)

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

(22,219)

 

7,950

 

(14,269)

 

(0.03)

 

730,114

 

(260,286)

 

469,828

 

0.86

Add: Net (Gains) Losses on Asset Dispositions

(205,835)

 

61,491

 

(144,344)

 

(0.26)

 

8,798

 

(4,183)

 

4,615

 

0.01

Add:  Impairments

320,617

 

(113,368)

 

207,249

 

0.37

 

6,307,592

 

(2,182,220)

 

4,125,372

 

7.56

Add:  Legal Settlement - Early Leasehold Termination

-

 

-

 

-

 

-

 

19,355

 

(6,900)

 

12,455

 

0.02

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

 

(15,047)

 

27,007

 

0.05

 

-

 

-

 

-

 

-

Add:  Acquisition - State Apportionment Change

-

 

16,424

 

16,424

 

0.03

 

-

 

-

 

-

 

-

Add:  Acquisition Costs

5,100

 

(88)

 

5,012

 

0.01

 

-

 

-

 

-

 

-

Adjustments to Net Income (Loss)

239,325

 

(35,278)

 

204,047

 

0.37

 

7,012,440

 

(2,454,045)

 

4,558,395

 

8.35

                               

Adjusted Net Income (Loss) (Non-GAAP)

$(1,318,180)

 

$425,541

 

$   (892,639)

 

$     (1.61)

 

$      90,884

 

$    (57,004)

 

$      33,880

 

$      0.06

                               

Average Number of Common Shares (GAAP)

                             

       Basic

           

553,384

             

545,697

       Diluted

           

553,384

             

545,697

                               

Average Number of Common Shares (Non-GAAP)

                             

      Basic

           

553,384

             

545,697

      Diluted

           

553,384

             

549,610

 

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 twelve-month periods ended December 31, 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

 

Twelve Months Ended

   

December 31,

 

December 31,

   

2016

 

2015

 

2016

 

2015

                         

Net Cash Provided by Operating Activities (GAAP)

$

804,745

 

$

615,813

 

$

2,359,063

 

$

3,595,165

                         

Adjustments:

                       

Exploration Costs (excluding Stock-Based Compensation Expenses) 

   

33,931

   

28,758

   

104,199

   

124,011

Excess Tax Benefits from Stock-Based Compensation

   

7,286

   

1,839

   

29,357

   

26,058

Changes in Components of Working Capital and Other Assets

                       

and Liabilities

                       

Accounts Receivable

   

220,939

   

(193,101)

   

232,799

   

(641,412)

Inventories

   

(33,131)

   

(31,443)

   

(170,694)

   

(58,450)

Accounts Payable

   

(127,165)

   

98,986

   

74,048

   

1,409,197

Accrued Taxes Payable

   

21,214

   

65,777

   

(92,782)

   

(11,798)

Other Assets

   

28,110

   

28,822

   

40,636

   

(118,143)

Other Liabilities

   

53,024

   

50,574

   

16,225

   

66,257

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

   

 

36,342

   

 

19,436

   

 

156,102

   

 

(499,767)

 

Discretionary Cash Flow (Non-GAAP)

 

$

1,045,295

 

$

685,461

 

$

2,748,953

 

$

3,891,118

                         

Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease

   

52%

         

-29%

     

 

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 twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions.  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

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2016

 

2015

 

2016

 

2015

                       

Net Loss (GAAP)

$

(142,352)

 

$

(284,296)

 

$

(1,096,686)

 

$

(4,524,515)

                       

Adjustments:

                     

     Interest Expense, Net

 

71,325

   

62,993

   

281,681

   

237,393

     Income Tax Benefit

 

(51,658)

   

(114,530)

   

(460,819)

   

(2,397,041)

     Depreciation, Depletion and Amortization

 

862,524

   

769,457

   

3,553,417

   

3,313,644

     Exploration Costs

 

39,110

   

34,946

   

124,953

   

149,494

     Dry Hole Costs

 

193

   

429

   

10,657

   

14,746

     Impairments 

 

297,946

   

168,171

   

620,267

   

6,613,546

             EBITDAX (Non-GAAP)

 

1,077,088

   

637,170

   

3,033,470

   

3,407,267

     Total (Gains) Losses on MTM Commodity Derivative Contracts  

 

65,787

   

(4,970)

   

99,608

   

(61,924)

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

 

-

   

69,093

   

(22,219)

   

730,114

     (Gains) Losses on Asset Dispositions, Net

 

(104,034)

   

3,656

   

(205,835)

   

8,798

                       

Adjusted EBITDAX (Non-GAAP)

$

1,038,841

 

$

704,949

 

$

2,905,024

 

$

4,084,255

                       

Adjusted EBITDAX (Non-GAAP) - Percentage Increase/Decrease

 

47%

         

-29%

     

 

EOG RESOURCES, INC.

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

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

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

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

(Unaudited; in millions, except ratio data)

           

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

           
 

At

 

At

 

December 31,

 

December 31,

 

2016

 

2015

           

Total Stockholders' Equity - (a)

$

13,982

 

$

12,943

           

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

 

6,986

   

6,655

Less: Cash 

 

(1,600)

   

(719)

Net Debt (Non-GAAP) - (c)

 

5,386

   

5,936

           

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

$

20,968

 

$

19,598

           

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

$

19,368

 

$

18,879

           

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

 

33%

   

34%

           

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

 

28%

   

31%

 

EOG RESOURCES, INC.

Reserves Supplemental Data

(Unaudited)

                 

2016 NET PROVED RESERVES RECONCILIATION SUMMARY  

           
 

 United 

     

 Other 

     
 

 States 

 

Trinidad

 

 International 

 

 Total 

 

CRUDE OIL & CONDENSATE (MMBbl)

               

Beginning Reserves

1,087.9

 

1.1

 

8.6

 

1,097.6

 

Revisions 

42.0

 

-

 

0.9

 

42.9

 

Purchases in place

25.8

 

-

 

-

 

25.8

 

Extensions, discoveries and other additions

123.4

 

-

 

-

 

123.4

 

Sales in place

(8.7)

 

-

 

-

 

(8.7)

 

Production 

(101.9)

 

(0.3)

 

(1.2)

 

(103.4)

 

Ending Reserves

1,168.5

 

0.8

 

8.3

 

1,177.6

 
 

NATURAL GAS LIQUIDS (MMBbl)

               

Beginning Reserves

382.9

 

-

 

-

 

382.9

 

Revisions 

53.7

 

-

 

-

 

53.7

 

Purchases in place

1.3

 

-

 

-

 

1.3

 

Extensions, discoveries and other additions

41.9

 

-

 

-

 

41.9

 

Sales in place

(33.5)

 

-

 

-

 

(33.5)

 

Production 

(29.9)

 

-

 

-

 

(29.9)

 

Ending Reserves

416.4

 

-

 

-

 

416.4

 
 

NATURAL GAS (Bcf) 

               

Beginning Reserves 

3,489.8

 

316.6

 

19.5

 

3,825.9

 

Revisions 

298.4

 

29.5

 

5.2

 

333.1

 

Purchases in place

91.5

 

-

 

-

 

91.5

 

Extensions, discoveries and other additions

202.1

 

59.9

 

-

 

262.0

 

Sales in place

(752.0)

 

-

 

-

 

(752.0)

 

Production 

(308.6)

 

(125.1)

 

(8.9)

 

(442.6)

 

Ending Reserves

3,021.2

 

280.9

 

15.8

 

3,317.9

 
 

OIL EQUIVALENTS (MMBoe) 

               

Beginning Reserves 

2,052.3

 

53.8

 

12.0

 

2,118.1

 

Revisions 

145.5

 

5.0

 

1.7

 

152.2

 

Purchases in place

42.3

 

-

 

-

 

42.3

 

Extensions, discoveries and other additions

199.0

 

10.0

 

-

 

209.0

 

Sales in place

(167.6)

 

-

 

-

 

(167.6)

 

Production 

(183.2)

 

(21.1)

 

(2.8)

 

(207.1)

 

Ending Reserves

2,088.3

 

47.7

 

10.9

 

2,146.9

 
 

 Net Proved Developed Reserves (MMBoe)  

               

 At December 31, 2015 

1,018.5

 

50.7

 

3.3

 

1,072.5

 

 At December 31, 2016 

1,038.5

 

44.5

 

10.9

 

1,093.9

 
 

2016 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) 

         
 

 United 

     

 Other 

     
 

 States 

 

Trinidad

 

 International 

 

 Total 

 
 

Acquisition Cost of Unproved Properties

$3,216.6

 

$       -

 

$                -

 

$3,216.6

 

Exploration Costs

156.3

 

2.7

 

6.8

 

165.8

 

Development Costs

2,228.0

 

75.4

 

30.3

 

2,333.7

 

Total Drilling

5,600.9

 

78.1

 

37.1

 

5,716.1

 

Acquisition Cost of Proved Properties

749.0

 

-

 

-

 

749.0

 

Total Exploration & Development Expenditures 

6,349.9

 

78.1

 

37.1

 

6,465.1

 

Gathering, Processing and Other

108.6

 

-

 

0.2

 

108.8

 

Asset Retirement Costs 

24.7

 

(3.2)

 

(41.4)

 

(19.9)

 

Total Expenditures

6,483.2

 

74.9

 

(4.1)

 

6,554.0

 

Proceeds from Sales in Place

(1,109.4)

 

-

 

(9.2)

 

(1,118.6)

 

Net Expenditures

$5,373.8

 

$   74.9

 

$            (13.3)

 

$5,435.4

 
 

RESERVE REPLACEMENT COSTS ($ / Boe ) * 

               

All-in Total, Net of Revisions 

$     6.50

 

$   5.21

 

$           21.82

 

$     6.52

 

All-in Total, Excluding Revisions Due to Price

$     5.14

 

$   6.05

 

$           21.82

 

$     5.22

 
 

RESERVE REPLACEMENT *

               

Drilling Only

109%

 

47%

 

0%

 

101%

 

All-in Total, Net of Revisions & Dispositions  

120%

 

71%

 

61%

 

114%

 

All-in Total, Excluding Revisions Due to Price

176%

 

61%

 

61%

 

163%

 

All-in Total, Liquids

187%

 

0%

 

75%

 

185%

 
 

*   See attached reconciliation schedule for calculation methodology

 

EOG RESOURCES, INC.

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

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

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

(Unaudited; in millions, except ratio information)

                 

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

                 

For the Twelve Months Ended December 31, 2016

               
                 
 

 United 

     

 Other 

     
 

 States 

 

 Trinidad 

 

 International 

 

 Total 

 
 

Total Costs Incurred in Exploration and Development Activities (GAAP)

$ 6,374.6

 

$     74.9

 

$      (4.3)

 

$  6,445.2

 

Less:  Asset Retirement Costs

(24.7)

 

3.2

 

41.4

 

19.9

 

          Non-Cash Acquisition Costs of Unproved Properties

(3,101.8)

 

-

 

-

 

(3,101.8)

 

          Non-Cash Acquisition Costs of Proved Properties

(732.3)

 

-

 

-

 

(732.3)

 

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

$ 2,515.8

 

$     78.1

 

$     37.1

 

$  2,631.0

 
 

Total Expenditures (GAAP)

$ 6,483.2

 

$     74.9

 

$      (4.1)

 

$  6,554.0

 

Less:  Asset Retirement Costs

(24.7)

 

3.2

 

41.4

 

19.9

 

          Non-Cash Acquisition Costs of Unproved Properties

(3,101.8)

 

-

 

-

 

(3,101.8)

 

          Non-Cash Acquisition Costs of Proved Properties

(732.3)

 

-

 

-

 

(732.3)

 

          Non-Cash Acquisition Costs of Other Assets

(16.6)

 

-

 

-

 

(16.6)

 

Total Cash Expenditures (Non-GAAP) 

$ 2,607.8

 

$     78.1

 

$     37.3

 

$  2,723.2

 
 

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

               

Revisions due to price (b)

(102.8)

 

2.1

 

-

 

(100.7)

 

Revisions other than price

248.3

 

2.9

 

1.7

 

252.9

 

Purchases in place

42.3

 

-

 

-

 

42.3

 

Extensions, discoveries and other additions (c)

199.0

 

10.0

 

-

 

209.0

 

Total Proved Reserve Additions (d) 

386.8

 

15.0

 

1.7

 

403.5

 

Sales in place

(167.6)

 

-

 

-

 

(167.6)

 

Net Proved Reserve Additions From All Sources (e) 

219.2

 

15.0

 

1.7

 

235.9

 
 

Production (f) 

183.2

 

21.1

 

2.8

 

207.1

 
 

RESERVE REPLACEMENT COSTS ($ / Boe)

               

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

$     6.50

 

$     5.21

 

$    21.82

 

$      6.52

 

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

$     5.14

 

$     6.05

 

$    21.82

 

$      5.22

 
 

RESERVE REPLACEMENT

               

Drilling Only (c / f) 

109%

 

47%

 

0%

 

101%

 

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

120%

 

71%

 

61%

 

114%

 

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

176%

 

61%

 

61%

 

163%

 
 

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

               

Revisions

95.7

 

-

 

0.9

 

96.6

 

Purchases in place

27.1

 

-

 

-

 

27.1

 

Extensions, discoveries and other additions (g)

165.3

 

-

 

-

 

165.3

 

Total Proved Reserve Additions 

288.1

 

-

 

0.9

 

289.0

 

Sales in place

(42.2)

 

-

 

-

 

(42.2)

 

Net Proved Reserve Additions From All Sources (h) 

245.9

 

-

 

0.9

 

246.8

 
 

Production (i)   

131.8

 

0.3

 

1.2

 

133.3

 
 

RESERVE REPLACEMENT - LIQUIDS

               

Drilling Only (g / i) 

125%

 

0%

 

0%

 

124%

 

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

187%

 

0%

 

75%

 

185%

 
                 

EOG RESOURCES, INC.

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

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

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

(Unaudited; in millions, except ratio information)

                 

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

                 

For the Twelve Months Ended December 31, 2016

               
             

 Total 

 

PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)

               

Total Costs Incurred in Exploration and Development Activities (GAAP)

           

$  6,445.2

 

Less:  Asset Retirement Costs

           

19.9

 

           Acquisition Costs of Unproved Properties

           

(3,216.6)

 

           Acquisition Cost of Proved Properties

           

(749.0)

 

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

           

$  2,499.5

 
 

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

           

209.0

 

Add: Conversion of proved undeveloped reserves to proved developed

           

149.2

 

Less: Proved undeveloped extensions and discoveries

           

(138.1)

 

Proved Developed Reserves - Extensions and discoveries (MMBoe)

           

220.1

 
 

Total Proved Reserves - Revisions (MMBoe)

           

152.2

 

Less: Proved Undeveloped Reserves - Revisions

           

(64.4)

 

         Proved Developed - Revisions due to price

           

76.7

 

Proved Developed Reserves - Revisions other than price (MMBoe)

           

164.5

 
 

Proved Developed Reserves - Extensions and discoveries plus revisions

               

   other than price (MMBoe) (k)

           

384.6

 
                 

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

     

$      6.50

 

 

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 February 20, 2017, 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

                       

2017

                   

January 2017 (closed)

           

35,000

 

$           50.04

February 1, 2017 through June 30, 2017

       

35,000

 

50.04

                       
                       

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 U.S. 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 February 20, 2017, 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 December 31, 2016 (closed)

 

70,000

 

$         54.25

 

$           45.00

                       
                       

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 20, 2017, 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

                       

2018

                   

March 1, 2018 through November 30, 2018

       

35,000

 

$             3.00

                       
                       

EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts.  The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price.  In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts.  The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price.  Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 20, 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)

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

                       
                       

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

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.

                       
   

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 (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) (Non-GAAP)

                     
                       

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

 

-8.1%

   

-29.5%

   

17.6%

     
                       

ROE (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.

First Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing

                       

     (a)  First Quarter and Full Year 2017 Forecast

                     
                       

The forecast items for the first 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)

         
   

1Q 2017

   

Full Year 2017

Daily Sales Volumes

                     

     Crude Oil and Condensate Volumes (MBbld)

                     

          United States

 

300.0

-

 

310.0

   

320.0

-

 

335.0

          Trinidad

 

0.3

-

 

0.5

   

0.3

-

 

0.5

          Other International

 

2.0

-

 

4.0

   

4.0

-

 

7.0

               Total

 

302.3

-

 

314.5

   

324.3

-

 

342.5

                       

     Natural Gas Liquids Volumes (MBbld)

                     

               Total

 

72.0

-

 

78.0

   

72.0

-

 

82.0

                       

     Natural Gas Volumes (MMcfd)

                     

          United States

 

670

-

 

710

   

725

-

 

760

          Trinidad

 

300

-

 

330

   

275

-

 

315

          Other International

 

18

-

 

24

   

25

-

 

30

               Total

 

988

-

 

1,064

   

1,025

-

 

1,105

                       

     Crude Oil Equivalent Volumes (MBoed)  

                     

          United States

 

483.7

-

 

506.3

   

512.8

-

 

543.7

          Trinidad

 

50.3

-

 

55.5

   

46.1

-

 

53.0

          Other International

 

5.0

-

 

8.0

   

8.2

-

 

12.0

               Total

 

539.0

-

 

569.8

   

567.1

-

 

608.7

                       

Operating Costs

                     

     Unit Costs ($/Boe)

                     

          Lease and Well

$

4.60

-

$

5.00

 

$

4.30

-

$

5.00

          Transportation Costs

$

3.40

-

$

4.00

 

$

3.10

-

$

3.90

          Depreciation, Depletion and Amortization

$

15.80

-

$

16.10

 

$

15.50

-

$

16.00

                       

Expenses ($MM)

                     

     Exploration, Dry Hole and Impairment

$

95

-

$

125

 

$

415

-

$

465

     General and Administrative

$

90

-

$

100

 

$

365

-

$

395

     Gathering and Processing 

$

28

-

$

30

 

$

105

-

$

125

     Capitalized Interest

$

7

-

$

8

 

$

25

-

$

30

     Net Interest

$

69

-

$

71

 

$

273

-

$

283

                       

Taxes Other Than Income (% of Wellhead Revenue)

 

6.7%

-

 

7.1%

   

6.5%

-

 

6.9%

                       

Income Taxes

                     

     Effective Rate 

 

31%

-

 

36%

   

31%

-

 

36%

     Current Taxes ($MM)

$

30

-

$

45

 

$

130

-

$

170

                       

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 to Benchmark Commodity Pricing in text)

                     

     Crude Oil and Condensate ($/Bbl)

                     

          Differentials

                     

               United States - above (below) WTI

$

(2.00)

-

$

(1.00)

 

$

(2.50)

-

$

(0.50)

               Trinidad - above (below) WTI

$

(9.75)

-

$

(7.75)

 

$

(9.50)

-

$

(7.50)

               Other International - above (below) WTI

$

(10.00)

-

$

(8.00)

 

$

(3.00)

-

$

0.00

                       

     Natural Gas Liquids

                     

          Realizations as % of WTI

 

31%

-

 

35%

   

31%

-

 

35%

                       

     Natural Gas ($/Mcf)

                     

          Differentials

                     

               United States - above (below) NYMEX Henry Hub

$

(1.10)

-

$

(0.70)

 

$

(1.15)

-

$

(0.65)

                       

          Realizations

                     

               Trinidad

$

2.00

-

$

2.40

 

$

1.90

-

$

2.50

               Other International

$

3.75

-

$

4.25

 

$

3.50

-

$

4.50

                       

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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