EOG Resources Announces Excellent Second Quarter 2018 Results; Adds Two New Premium Shale Plays and Significant Resource Potential in the Powder River Basin; Raises Common Stock Dividend 19 Percent

Company Release - 8/2/2018 4:15 PM ET

HOUSTON, Aug. 2, 2018 /PRNewswire/ --

  • Beats Oil, Natural Gas and NGL Production Targets
  • Maintains Full-Year Exploration and Development Expenditure Target
  • Announces Powder River Basin Mowry and Niobrara Shale Plays and Expands Turner Sand Inventory, Adding 1,560 Net Premium Drilling Locations and 1.9 BnBoe Net Resource Potential
  • Increases Common Stock Dividend a Second Time in 2018; Year-to-Date Increase 31 Percent

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2018 net income of $696.7 million, or $1.20 per share. This compares to second quarter 2017 net income of $23.1 million, or $0.04 per share. 

Adjusted non-GAAP net income for the second quarter 2018 was $794.9 million, or $1.37 per share, compared to adjusted non-GAAP net income of $46.7 million, or $0.08 per share, for the same prior year period. 

EOG's premium portfolio of high-return plays generated strong financial performance in the second quarter 2018.  Higher commodity prices, increased production volumes and overall per-unit cost reductions resulted in a dramatic increase in adjusted non-GAAP net income, compared to the second quarter 2017.  Higher commodity prices and production volumes also resulted in significant increases in discretionary cash flow and adjusted EBITDAX.  Adjusted non-GAAP net income is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items.  Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Operational Highlights
EOG grew total crude oil production 15 percent year-over-year to 384,600 barrels of oil per day (Bopd), setting a company record.  Total company production increased 16 percent in the second quarter 2018 compared to the same prior year period.  Growth in the Delaware Basin, Eagle Ford and Powder River Basin drove EOG's strong performance.  The company maintained its target for 18 percent crude oil growth for full year 2018.

Total per-unit operating expenses declined during the second quarter 2018 compared to the same prior year period.  A 16 percent reduction in depreciation, depletion and amortization rates and an 18 percent decrease in transportation rates were the largest contributors to the overall per-unit cost reduction. 

EOG maintained its forecast for 2018 exploration and development expenditures of $5.4 to $5.8 billion, excluding acquisitions and non-cash transactions.  The company also maintained its target to reduce average well costs by five percent in 2018.   

"EOG delivered a strong quarter, meeting or exceeding expectations for production volumes, price realizations and operating expenses," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "The EOG machine is firing on all cylinders.  We grew crude oil production in five operating areas while reducing costs.  Our disciplined investments across a diverse array of premium plays are generating record rates of return."

Dividend Increase
EOG's Board of Directors increased the cash dividend on the common stock by 19 percent. Effective with the dividend payable October 31, 2018, to holders of record as of October 17, 2018, the board declared a quarterly dividend of $0.22 per share on the common stock. The indicated annual rate is $0.88 per share.

"EOG's premium drilling strategy has reset the profitability of the company and we are confident our premium investments can sustain a larger dividend.  Therefore, we increased the common stock dividend for a second time in 2018, reaffirming our commitment to deliver more value for long-term stockholders," Thomas said.

Powder River Basin
EOG significantly expanded the estimated resource potential of its 400,000 net acre position in the pressure cell of the Powder River Basin in Wyoming.  The Mowry and Niobrara shales along with the Turner sand have combined estimated net resource potential of 2.1 billion barrels of oil equivalent (BnBoe).  The company has identified over 1,600 net premium drilling locations, representing more than 30 years of drilling inventory at the current pace.  The Powder River Basin is now EOG's third largest asset. 

EOG is operating a two-rig program in 2018 and expects to complete approximately 45 net wells.  Targeted well costs across these plays range from $4.5 to $6.1 million per well.  These costs have declined significantly due to faster drilling speeds and more efficient completion operations.  The company plans to increase its drilling activity during 2019 and install additional infrastructure in preparation for initiating a long-term development program.    

EOG has identified 141,000 net acres prospective for the Mowry.  The company has identified an initial 875 net premium locations with estimated net resource potential of 1.2 BnBoe.  EOG completed two Mowry wells in the second quarter.  The Ballista 204-1102H and the Flatbow 423-1720H were completed with an average treated lateral length of 9,100 feet per well and average 30-day initial production rates per well of 2,190 barrels of oil equivalent per day (Boed), or 760 Bopd, 495 barrels per day (Bpd) of natural gas liquids (NGLs) and 5.6 million cubic feet per day (MMcfd) of natural gas.  Well costs are targeted at $6.1 million for a 9,500 foot lateral well.  Reserves per well are estimated to be 1,400 thousand barrels of oil equivalent (MBoe), net after royalty, with an oil mix of 28 percent.

In the Niobrara, EOG has identified 89,000 prospective net acres with an initial 555 net premium locations.  The Niobrara has estimated net resource potential of 640 million barrels of oil equivalent (MMBoe).  Reserves per well are estimated to be 1,150 MBoe, net after royalty, with a 48 percent oil mix.  Targeted well cost is $5.9 million for a 9,500 foot lateral well. 

EOG has completed five horizontal Niobrara wells in the past two years.  The Ballista 213-1301H was brought to sales in June 2016 with a treated lateral length of 9,500 feet and 30-day initial production rate of 2,090 Boed, or 1,180 Bopd, 310 Bpd of NGLs and 3.6 MMcfd of natural gas.  Since coming on-line, the well has produced 225,000 barrels of crude oil and over one billion cubic feet of natural gas.

EOG holds 169,000 net acres prospective for the Turner with 200 net premium locations remaining to be drilled.  The company has completed 50 wells in the play since the last premium inventory assessment in 2017.  Reserves per well are estimated to be 500 MBoe, net after royalty, with a 46 percent oil mix.  Targeted well cost is $4.5 million for an 8,000 foot lateral well. 

In the second quarter, EOG completed seven Turner wells with an average well cost of $4.1 million per well.  These wells were completed with an average treated lateral length of 6,200 feet per well and average 30-day initial production rates per well of 915 Boed, or 760 Bopd, 50 Bpd of NGLs and 0.6 MMcfd of natural gas. 

"These two new high-return plays in the Powder River Basin further diversify EOG's premium portfolio, supporting high-return organic growth," Thomas said. "We acquired the acreage at low cost and applied our industry-leading exploration expertise to identify the best targets.  We further leveraged this position with our low-cost operating culture.  The Powder River Basin, with 2.1 BnBoe of resource potential, is poised to become a major asset in EOG's diverse portfolio of premium plays."

Delaware Basin
EOG has identified an additional 375 net undrilled premium locations in the Delaware Basin, raising the total to 4,815 locations and more than replacing the 250 locations drilled since the last premium inventory assessment in 2017.  Cost reductions from infrastructure investments and the delineation of additional drilling targets supported the identification of the new premium locations. 

During the second quarter 2018, EOG continued development of its 416,000 net acre position in the Delaware Basin with ongoing testing of additional targets and spacing.  Lateral lengths increased further during the quarter, and the company increased its use of locally sourced sand beginning in June.  Operations also commenced at additional locations on EOG's new crude oil gathering system commissioned earlier in 2018. 

In the Delaware Basin Wolfcamp, EOG completed the Quanah Parker 8H-11H.  This four-well package was drilled on 440-foot spacing staggered across two target intervals.  The wells were completed with an average treated lateral length of 9,900 feet per well and average 30-day initial production rates per well of 2,565 Boed, or 1,535 Bopd, 525 Bpd of NGLs and 3.0 MMcfd of natural gas. 

In the Delaware Basin Second Bone Spring, EOG completed the Bandit 29 State Com 501H-503H and 504Y, a four-well package with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,410 Boed, or 2,035 Bopd, 170 Bpd of NGLs and 1.3 MMcfd of natural gas. 

South Texas Eagle Ford and Austin Chalk
EOG also updated its premium inventory in the Eagle Ford, which now stands at 2,300 net undrilled premium locations.  The company completed 270 net wells since the last premium inventory assessment in 2017.  Lower well costs and further efficiencies from shifting to longer laterals enabled EOG to convert 145 additional locations to premium. 

The South Texas Eagle Ford remained a focal point of EOG's high-rate-of-return drilling program in the second quarter 2018.  With approximately two-thirds of the 7,200 total identified drilling locations remaining to be developed, the company is utilizing the flexibility of its contiguous 520,000 net acre position in the oil window of this world-class play to increase the size of drilling units to accommodate longer-lateral wells.  Wells completed in the second quarter had average treated lateral lengths of 7,200 feet per well.  In the western half of the field, wells completed in the second quarter had average treated lateral lengths in excess of 10,000 feet per well.  At the same time, EOG continues to test various spacing patterns and lateral targets.  Strong well results speak to the play's status as an important contributor to total company crude oil production growth.

Notable wells in the second quarter included the Sandies Creek A-F 1H-6H, a six-well package in DeWitt County, TX with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 3,205 Boed, or 2,320 Bopd, 450 Bpd of NGLs and 2.6 MMcfd of natural gas.  In Karnes County, TX, EOG completed the Hickok 5H-8H, a four-well package with an average treated lateral length of 5,000 feet per well and average 30-day initial production rates per well of 2,685 Boed, or 2,020 Bopd, 340 Bpd of NGLs and 2.0 MMcfd of natural gas.  On the western side of the Eagle Ford in McMullen County, TX, EOG completed the Antrim Cook Unit 15H-18H, a four-well package with an average treated lateral length of 11,200 feet per well and average 30-day initial production rates per well of 2,240 Boed, or 2,210 Bopd, 15 Bpd of NGLs and 0.1 MMcfd of natural gas.

EOG also continued delineation of the South Texas Austin Chalk, completing five wells in the second quarter 2018.   

Williston Basin and DJ Basin
During the second quarter 2018, EOG resumed completion activity in the Williston Basin as part of its seasonal development program and continued development of its premium DJ Basin Codell play in Wyoming.  The company further lowered well costs by improving drilling and completion times and making other efficiency improvements. 

In the North Dakota Williston Basin, EOG drilled nine wells and began production from two wells in the second quarter.  The Clarks Creek 108 and 155-0706H targeted the Three Forks formation in McKenzie County, ND and were completed with an average treated lateral length of 9,200 feet per well and average 30-day initial production rates per well of 2,980 Boed, or 2,240 Bopd, 345 Bpd of NGLs and 2.4 MMcfd of natural gas. 

EOG began production from eight wells in the DJ Basin during the second quarter 2018.  In particular, a four-well package of DJ Basin Codell wells in Laramie County, WY, the Windy 576 and 577-1702H and the Windy 591 and 593-1705H, was completed with an average treated lateral length of 9,300 feet per well and average 30-day initial production rates per well of 870 Boed, or 755 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas.  All four of these wells are premium.  They were drilled in an average of 4.4 days per well with an average cost of $3.4 million per well.

Capital Structure
At June 30, 2018, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 27 percent.  Considering cash on the balance sheet at the end of the second quarter, EOG's net debt was $5.4 billion for a net debt-to-total capitalization ratio of 24 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Hedging Activity
During the second quarter 2018, EOG entered into additional crude oil derivative contracts.  A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables. 

Conference Call August 3, 2018
EOG's second quarter 2018 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, August 3, 2018.  To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.  The webcast will be archived on EOG's website for one year.

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

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

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

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

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

For Further Information Contact:

Investors


David J. Streit


(713) 571-4902


Neel Panchal


(713) 571-4884


W. John Wagner


(713) 571-4404




Media and Investors


Kimberly M. Ehmer


(713) 571-4676

 

EOG RESOURCES, INC.

Financial Report

(Unaudited; in millions, except per share data)














Three Months Ended


Six Months Ended


June 30,


June 30,


2018


2017


2018


2017













Net Operating Revenues and Other

$

4,238.1


$

2,612.5


$

7,919.2


$

5,223.0

Net Income 

$

696.7


$

23.1


$

1,335.3


$

51.6

Net Income Per Share 












        Basic

$

1.21


$

0.04


$

2.32


$

0.09

        Diluted

$

1.20


$

0.04


$

2.30


$

0.09

Average Number of Common Shares












        Basic


576.1



574.4



576.0



574.2

        Diluted


580.4



578.5



580.0



578.6

























Summary Income Statements

(Unaudited; in thousands, except per share data)














Three Months Ended


Six Months Ended


June 30,


June 30,


2018


2017


2018


2017

Net Operating Revenues and Other








        Crude Oil and Condensate

$

2,377,528


$

1,445,454


$

4,478,836


$

2,875,515

        Natural Gas Liquids


286,354



146,907



507,769



300,351

        Natural Gas


300,845



224,008



600,611



454,610

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


(185,883)



9,446



(245,654)



71,466

        Gathering, Processing and Marketing


1,436,436



778,797



2,538,258



1,505,334

        Losses on Asset Dispositions, Net


(6,317)



(8,916)



(21,286)



(25,674)

        Other, Net


29,114



16,776



60,705



41,435

               Total


4,238,077



2,612,472



7,919,239



5,223,037

Operating Expenses












        Lease and Well


314,604



255,186



614,668



510,963

        Transportation Costs


177,797



186,356



354,754



365,070

        Gathering and Processing Costs


109,169



34,746



210,514



72,890

        Exploration Costs


47,478



34,711



82,314



91,605

        Dry Hole Costs


4,902



27



4,902



27

        Impairments 


51,708



78,934



116,317



272,121

        Marketing Costs


1,420,463



790,599



2,526,853



1,527,135

        Depreciation, Depletion and Amortization


848,674



865,384



1,597,265



1,681,420

        General and Administrative


104,083



108,507



198,781



205,745

        Taxes Other Than Income


194,268



130,114



373,352



260,407

               Total


3,273,146



2,484,564



6,079,720



4,987,383













Operating Income 


964,931



127,908



1,839,519



235,654













Other Income (Expense), Net


(8,551)



4,972



(7,824)



8,123













Income Before Interest Expense and Income Taxes


956,380



132,880



1,831,695



243,777













Interest Expense, Net


63,444



70,413



125,400



141,928













Income Before Income Taxes


892,936



62,467



1,706,295



101,849













Income Tax Provision


196,205



39,414



370,975



50,279













Net Income 

$

696,731


$

23,053


$

1,335,320


$

51,570













Dividends Declared per Common Share

$

0.1850


$

0.1675


$

0.3700


$

0.3350













 

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)














Three Months Ended


Six Months Ended


June 30,


June 30,


2018


2017


2018


2017

Wellhead Volumes and Prices




Crude Oil and Condensate Volumes (MBbld) (A)




      United States


379.2



333.1



369.5



322.8

      Trinidad


0.8



0.8



0.9



0.8

      Other International (B)


4.6



0.8



3.6



1.6

            Total


384.6



334.7



374.0



325.2













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












      United States

$

67.91


$

47.51


$

66.13


$

48.89

      Trinidad


60.57



39.64



57.59



40.63

      Other International (B)


70.88



35.13



71.14



44.66

            Composite


67.93



47.46



66.16



48.85













Natural Gas Liquids Volumes (MBbld) (A)












      United States


112.9



86.6



106.8



82.7

      Other International (B)


-



-



-



-

            Total


112.9



86.6



106.8



82.7













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












      United States

$

27.86


$

18.65


$

26.27


$

20.06

      Other International (B)


-



-



-



-

            Composite


27.86



18.65



26.27



20.06













Natural Gas Volumes (MMcfd) (A)












      United States


914



755



884



742

      Trinidad


282



320



288



314

      Other International (B)


32



21



30



21

            Total


1,228



1,096



1,202



1,077













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












      United States

$

2.56


$

2.14


$

2.65


$

2.23

      Trinidad


2.98



2.40



2.93



2.48

      Other International (B)


4.10



3.66



4.22



3.71

            Composite


2.69

(D)


2.25



2.76

(D)


2.33













Crude Oil Equivalent Volumes (MBoed) (E)












      United States 


644.4



545.6



623.6



529.2

      Trinidad


47.8



54.1



48.8



53.1

      Other International (B)


10.0



4.2



8.8



5.1

            Total


702.2



603.9



681.2



587.4













Total MMBoe (E)


63.9



55.0



123.3



106.3













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

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

(C) Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2018).

(D) Includes positive revenue adjustments of $0.39 per Mcf and $0.40 per Mcf for the three and six months ended June 30, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Condensed Consolidated Financial Statements on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas revenues.

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

 

EOG RESOURCES, INC.

Summary Balance Sheets

(Unaudited; in thousands, except share data)








June 30,


December 31,


2018


2017

ASSETS

Current Assets






     Cash and Cash Equivalents

$

1,008,215


$

834,228

     Accounts Receivable, Net


1,907,990



1,597,494

     Inventories


670,994



483,865

     Assets from Price Risk Management Activities


1,840



7,699

     Income Taxes Receivable


364,119



113,357

     Other


278,694



242,465

            Total


4,231,852



3,279,108







Property, Plant and Equipment






     Oil and Gas Properties (Successful Efforts Method)


55,319,050



52,555,741

     Other Property, Plant and Equipment


4,141,479



3,960,759

            Total Property, Plant and Equipment


59,460,529



56,516,500

     Less:  Accumulated Depreciation, Depletion and Amortization


(32,306,734)



(30,851,463)

            Total Property, Plant and Equipment, Net


27,153,795



25,665,037

Deferred Income Taxes


17,067



17,506

Other Assets


689,666



871,427

Total Assets

$

32,092,380


$

29,833,078







LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities






     Accounts Payable

$

2,336,952


$

1,847,131

     Accrued Taxes Payable


213,461



148,874

     Dividends Payable


106,569



96,410

     Liabilities from Price Risk Management Activities


195,457



50,429

     Current Portion of Long-Term Debt


1,262,540



356,235

     Other


182,322



226,463

            Total


4,297,301



2,725,542













Long-Term Debt


5,172,257



6,030,836

Other Liabilities


1,304,624



1,275,213

Deferred Income Taxes


3,865,804



3,518,214

Commitments and Contingencies












Stockholders' Equity






     Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 






        579,597,990 Shares Issued at June 30, 2018 and 578,827,768






        Shares Issued at December 31, 2017  


205,796



205,788

     Additional Paid in Capital


5,591,643



5,536,547

     Accumulated Other Comprehensive Loss


(17,512)



(19,297)

     Retained Earnings


11,714,656



10,593,533

     Common Stock Held in Treasury, 410,969 Shares at June 30, 2018






        and 350,961 Shares at December 31, 2017


(42,189)



(33,298)

            Total Stockholders' Equity


17,452,394



16,283,273

Total Liabilities and Stockholders' Equity

$

32,092,380


$

29,833,078

 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)








Six Months Ended


June 30,


2018


2017

Cash Flows from Operating Activities






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






     Net Income

$

1,335,320


$

51,570

     Items Not Requiring (Providing) Cash






            Depreciation, Depletion and Amortization


1,597,265



1,681,420

            Impairments 


116,317



272,121

            Stock-Based Compensation Expenses


67,289



58,061

            Deferred Income Taxes


347,586



35,162

            Losses on Asset Dispositions, Net


21,286



25,674

            Other, Net


13,507



(6,691)

     Dry Hole Costs


4,902



27

     Mark-to-Market Commodity Derivative Contracts






            Total (Gains) Losses


245,654



(71,466)

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


(88,334)



2,591

     Other, Net


(261)



(185)

     Changes in Components of Working Capital and Other Assets and Liabilities






            Accounts Receivable


(309,751)



103,786

            Inventories


(192,219)



(6,129)

            Accounts Payable


455,977



76,704

            Accrued Taxes Payable


22,535



(39,124)

            Other Assets


(62,843)



(61,089)

            Other Liabilities


(53,168)



(66,869)

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


(27,279)



(79,138)

Net Cash Provided by Operating Activities


3,493,783



1,976,425







Investing Cash Flows






     Additions to Oil and Gas Properties


(2,980,286)



(1,885,417)

     Additions to Other Property, Plant and Equipment


(144,858)



(88,076)

     Proceeds from Sales of Assets


8,276



175,260

     Changes in Components of Working Capital Associated with Investing Activities


27,250



79,138

Net Cash Used in Investing Activities


(3,089,618)



(1,719,095)







Financing Cash Flows






     Dividends Paid


(203,610)



(192,984)

     Treasury Stock Purchased


(32,023)



(21,678)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 


11,145



9,608

     Repayment of Capital Lease Obligation


(3,354)



(3,251)

     Changes in Working Capital Associated with Financing Activities


29



-

Net Cash Used in Financing Activities


(227,813)



(208,305)







Effect of Exchange Rate Changes on Cash


(2,365)



523







Increase in Cash and Cash Equivalents


173,987



49,548

Cash and Cash Equivalents at Beginning of Period


834,228



1,599,895

Cash and Cash Equivalents at End of Period

$

1,008,215


$

1,649,443

 

EOG RESOURCES, INC.

Second Quarter 2018 Well Results by Play

(Unaudited)


















Wells Online




Initial Gross 30-Day Average Production Rate



Gross


Net


Lateral
Length
(ft)


Crude Oil and
Condensate
(Bbld) (A)


Natural Gas
Liquids
(Bbld) (A)


 Natural Gas
(MMcfd) (A)


Crude Oil
Equivalent
(Boed) (B)

Delaware Basin















Wolfcamp


62


58


6,400


1,255


320


2.3


1,960

Bone Spring


13


9


5,700


1,150


190


1.6


1,615

Leonard


7


3


4,500


965


350


2.6


1,745
















South Texas Eagle Ford


74


67


7,200


1,530


195


1.1


1,920
















South Texas Austin Chalk


5


5


7,900


2,355


470


2.7


3,275
















Powder River Basin Turner


7


6


6,200


760


50


0.6


915
















DJ Basin Codell


8


4


9,300


675


55


0.2


765
















Williston Basin Bakken/Three Forks


2


2


9,200


2,240


345


2.4


2,980
















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

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

 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Net Income (Non-GAAP)

To Net Income (GAAP)

(Unaudited; in thousands, except per share data)

































The following chart adjusts the three-month and six-month periods ended June 30, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.


















Three Months Ended 


Three Months Ended 


June 30, 2018


June 30, 2017




















Income




Diluted




Income




Diluted


Before


Tax


After


Earnings


Before


Tax


After


Earnings


Tax


Impact


Tax


per Share


Tax


Impact


Tax


per Share

Reported Net Income (GAAP)

$        892,936


$      (196,205)


$        696,731


$         1.20


$       62,467


$      (39,414)


$       23,053


$         0.04

Adjustments:
















(Gains) Losses on Mark-to-Market Commodity
















     Derivative Contracts

185,883


(40,944)


144,939


0.25


(9,446)


3,426


(6,020)


(0.01)

Net Cash Received from (Payments for)
















     Settlements of Commodity Derivative
















     Contracts

(66,369)


14,619


(51,750)


(0.09)


679


(245)


434


-

Add:  Net Losses on Asset Dispositions

6,317


(1,375)


4,942


0.01


8,916


(3,151)


5,765


0.01

Add:  Impairments

-


-


-


-


23,397


(8,477)


14,920


0.03

Add:  Legal Settlement - Early Lease Termination

-


-


-


-


10,202


(3,657)


6,545


0.01

Add:  Joint Venture Transaction Costs

-


-


-


-


3,056


(1,095)


1,961


-

Adjustments to Net Income 

125,831


(27,700)


98,131


0.17


36,804


(13,199)


23,605


0.04

















Adjusted Net Income (Non-GAAP)

$     1,018,767


$      (223,905)


$        794,862


$         1.37


$       99,271


$      (52,613)


$       46,658


$         0.08

















Average Number of Common Shares (GAAP)
















       Basic







576,135








574,439

       Diluted







580,375








578,483


















































Six Months Ended 


Six Months Ended 


June 30, 2018


June 30, 2017




















Income




Diluted




Income




Diluted


Before


Tax


After


Earnings


Before


Tax


After


Earnings


Tax


Impact


Tax


per Share


Tax


Impact


Tax


per Share

Reported Net Income (GAAP)

$     1,706,295


$      (370,975)


$     1,335,320


$         2.30


$      101,849


$      (50,279)


$       51,570


$         0.09

Adjustments:
















(Gains) Losses on Mark-to-Market Commodity
















     Derivative Contracts

245,654


(54,110)


191,544


0.33


(71,466)


25,617


(45,849)


(0.08)

Net Cash Received from (Payments for)
















     Settlements of Commodity Derivative
















     Contracts

(88,334)


19,457


(68,877)


(0.12)


2,591


(929)


1,662


-

Add:  Net Losses on Asset Dispositions

21,286


(4,699)


16,587


0.03


25,674


(8,887)


16,787


0.03

Add:  Impairments

20,876


(4,598)


16,278


0.03


161,148


(57,764)


103,384


0.18

Add:  Legal Settlement - Early Lease Termination

-


-


-


-


10,202


(3,657)


6,545


0.01

Add:  Joint Venture Transaction Costs

-


-


-


-


3,056


(1,095)


1,961


-

Less:  Tax Reform Impact

-


(6,524)


(6,524)


(0.01)


-


-


-


-

Adjustments to Net Income 

199,482


(50,474)


149,008


0.26


131,205


(46,715)


84,490


0.14

















Adjusted Net Income (Non-GAAP)

$     1,905,777


$      (421,449)


$     1,484,328


$         2.56


$      233,054


$      (96,994)


$     136,060


$         0.23

















Average Number of Common Shares (GAAP)
















       Basic







575,953








574,162

       Diluted







580,007








578,573

















 

EOG RESOURCES, INC.


Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)


To Net Cash Provided By Operating Activities (GAAP)


(Unaudited; in thousands)















Calculation of Free Cash Flow (Non-GAAP)


(Unaudited; in thousands)










The following chart reconciles the three-month and six-month periods ended June 30, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.  EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the six months ended June 30, 2018.  EOG management uses this information for comparative purposes within the industry.
















Three Months Ended


Six Months Ended



June 30,


June 30,



2018


2017


2018


2017















Net Cash Provided by Operating Activities (GAAP)

$

1,941,617


$

1,078,376


$

3,493,783


$

1,976,425















Adjustments:













Exploration Costs (excluding Stock-Based Compensation Expenses) 


41,748



29,402



69,684



80,136


Other Non-Current Income Taxes - Net Receivable


73,441



-



192,362



-


Changes in Components of Working Capital and Other Assets













and Liabilities













Accounts Receivable


200,097



(75,098)



309,751



(103,786)


Inventories


85,420



30,865



192,219



6,129


Accounts Payable


(402,325)



(56,278)



(455,977)



(76,704)


Accrued Taxes Payable


(585)



511



(22,535)



39,124


Other Assets


53,980



16,412



62,843



61,089


Other Liabilities


24,113



15,618



53,168



66,869


Changes in Components of Working Capital Associated with 













Investing and Financing Activities


45,267



15,814



27,279



79,138










Discretionary Cash Flow (Non-GAAP)

$

2,062,773


$

1,055,622


$

3,922,577


$

2,128,420















Discretionary Cash Flow (Non-GAAP) - Percentage Increase


95%






84%































Discretionary Cash Flow (Non-GAAP)







$

3,922,577





Less:  













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








(3,198,028)





Dividends Paid (GAAP) 








(203,610)





Free Cash Flow (Non-GAAP)







$

520,939































(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the six months ended June 30, 2018:














Total Expenditures (GAAP)







$

3,373,573





Less:  













          Asset Retirement Costs








(30,956)





          Non-Cash Capital Lease Expenditures








(47,680)





          Non-Cash Acquisition Costs of Unproved Properties








(60,002)





          Acquisition Costs of Proved Properties








(36,907)





Total Cash Expenditures Excluding Acquisitions (Non-GAAP) 







$

3,198,028


















 

EOG RESOURCES, INC.

Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net,

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

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

 (Non-GAAP) to Net Income (GAAP)

(Unaudited; in thousands)













The following chart adjusts the three-month and six-month periods ended June 30, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), 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 losses on asset dispositions (Net).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.














Three Months Ended


Six Months Ended


June 30,


June 30,


2018


2017


2018


2017













Net Income (GAAP)

$

696,731


$

23,053


$

1,335,320


$

51,570













Adjustments:












     Interest Expense, Net


63,444



70,413



125,400



141,928

     Income Tax Provision 


196,205



39,414



370,975



50,279

     Depreciation, Depletion and Amortization


848,674



865,384



1,597,265



1,681,420

     Exploration Costs


47,478



34,711



82,314



91,605

     Dry Hole Costs


4,902



27



4,902



27

     Impairments 


51,708



78,934



116,317



272,121

             EBITDAX (Non-GAAP)


1,909,142



1,111,936



3,632,493



2,288,950

     Total (Gains) Losses on MTM Commodity Derivative Contracts  


185,883



(9,446)



245,654



(71,466)

     Net Cash Received from (Payments for) Settlements of Commodity












          Derivative Contracts


(66,369)



679



(88,334)



2,591

     Losses on Asset Dispositions, Net


6,317



8,916



21,286



25,674













Adjusted EBITDAX (Non-GAAP)

$

2,034,973


$

1,112,085


$

3,811,099


$

2,245,749













Adjusted EBITDAX (Non-GAAP) - Percentage Increase


83%






70%




 

EOG RESOURCES, INC.

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

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

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

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

(Unaudited; in millions, except ratio data)


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






At


At


June 30,


December 31,


2018


2017







Total Stockholders' Equity - (a)

$

17,452


$

16,283







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


6,435



6,387

Less: Cash 


(1,008)



(834)

Net Debt (Non-GAAP) - (c)


5,427



5,553







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

$

23,887


$

22,670







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

$

22,879


$

21,836







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


27%



28%







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


24%



25%

 

EOG RESOURCES, INC.

Crude Oil and Natural Gas Financial Commodity

Derivative Contracts


EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.  Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors.  EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential).  Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through July 27, 2018.  The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.



Midland Differential Basis Swap Contracts






Weighted








Average Price






Volume


Differential






(Bbld) 


($/Bbl) 

2018








January 1, 2018 through August 31, 2018 (closed)






15,000


$             1.063

September 1, 2018 through December 31, 2018 






15,000


1.063









2019








January 1, 2019 through December 31, 2019 






20,000


$             1.075

















EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential).  Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through July 27, 2018.  The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.





















Gulf Coast Differential Basis Swap Contracts








Weighted










Average Price








Volume


Differential








(Bbld) 


($/Bbl) 

2018








January 1, 2018 through August 31, 2018 (closed)






37,000


$             3.818

September 1, 2018 through September 30, 2018 






37,000


3.818

October 1, 2018 through December 31, 2018 






52,000


3.911









2019








January 1, 2019 through December 31, 2019 






8,000


$             5.660

















Presented below is a comprehensive summary of EOG's crude oil price swap contracts through July 27, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl.  





















Crude Oil Price Swap Contracts








Weighted








Volume


Average Price








(Bbld) 


($/Bbl) 

2018








January 1, 2018 through June 30, 2018 (closed)






134,000


$             60.04

July 1, 2018 through December 31, 2018






134,000


60.04





















Presented below is a comprehensive summary of EOG's natural gas price swap contracts through July 27, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.





















Natural Gas Price Swap Contracts










Weighted








Volume


Average Price








(MMBtud)


($/MMBtu)

2018








March 1, 2018 through August 31, 2018 (closed)






35,000


$               3.00

September 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 July 27, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.





















Natural Gas Option Contracts




Call Options Sold


Put Options Purchased






Weighted




Weighted




Volume


Average Price


Volume


Average Price




(MMBtud) 


($/MMBtu) 


(MMBtud)


($/MMBtu)

2018








March 1, 2018 through August 31, 2018 (closed)


120,000


$               3.38


96,000


$               2.94

September 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

U.S. New York Mercantile Exchange









 

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)


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



Direct ATROR

Based on Cash Flow and Time Value of Money

  - Estimated future commodity prices and operating costs

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

Excludes Indirect Capital

  - Gathering and Processing and other Midstream

  - Land, Seismic, Geological and Geophysical


Payback ~12 Months on 100% Direct ATROR Wells

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



Return on Equity / Return on Capital Employed 

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  - Eagle Ford, Bakken, Permian Facilities

  - Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

 

EOG RESOURCES, INC.

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

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

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

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

(Unaudited; in millions, except ratio data)
















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

















2017


2016


2015


2014


2013

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






























Net Interest Expense (GAAP)

$

274


$

282


$

237


$

201




Tax Benefit Imputed (based on 35%) 


(96)



(99)



(83)



(70)




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

$

178


$

183


$

154


$

131



















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

$

2,583


$

(1,097)


$

(4,525)


$

2,915




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


(1,934)

 (a) 


204

 (b) 


4,559

 (c) 


(199)

 (d) 



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

$

649


$

(893)


$

34


$

2,716



















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

$

16,283


$

13,982


$

12,943


$

17,713


$

15,418

Less: Tax Reform Impact


(2,169)



-



-



-



-

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

$

14,114


$

13,982


$

12,943


$

17,713


$

15,418
















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

$

15,133


$

13,463


$

15,328


$

16,566



















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

$

14,048


$

13,463


$

15,328


$

16,566



















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

$

6,387


$

6,986


$

6,655


$

5,906


$

5,909

Less: Cash                                                       


(834)



(1,600)



(719)



(2,087)



(1,318)

Net Debt (Non-GAAP) - (i) 

$

5,553


$

5,386


$

5,936


$

3,819


$

4,591
















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

$

22,670


$

20,968


$

19,598


$

23,619


$

21,327
















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

$

19,667


$

19,368


$

18,879


$

21,532


$

20,009
















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

$

19,518


$

19,124


$

20,206


$

20,771



















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


14.1%



-4.8%



-21.6%



14.7%



















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


4.2%



-3.7%



0.9%



13.7%



















Return on Equity (ROE)






























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


17.1%



-8.1%



-29.5%



17.6%



















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


4.6%



-6.6%



0.2%



16.4%



















* Average for the current and immediately preceding year


























































































Adjustments to Net Income (Loss) (GAAP)













































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















Year Ended December 31, 2017









 Before 



 Income Tax  



 After 









 Tax 



 Impact 



 Tax 







Adjustments:















    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

(12)


$

4


$

(8)







    Add:   Impairments of Certain Assets


261



(93)



168







    Add:   Net Losses on Asset Dispositions


99



(35)



64







    Add:   Legal Settlement - Early Lease Termination


10



(4)



6







    Add:   Joint Venture Transaction Costs


3



(1)



2







    Add:   Joint Interest Billings Deemed Uncollectible


5



(2)



3







    Less:  Tax Reform Impact


-



(2,169)



(2,169)







Total

$

366


$

(2,300)


$

(1,934)






















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















Year Ended December 31, 2016









 Before 



 Income Tax  



 After 









 Tax 



 Impact 



 Tax 







Adjustments:















    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

77


$

(28)


$

49







    Add:   Impairments of Certain Assets


321



(113)



208







    Less:  Net Gains on Asset Dispositions


(206)



62



(144)







    Add:   Trinidad Tax Settlement


-



43



43







    Add:   Voluntary Retirement Expense


42



(15)



27







    Add:   Acquisition - State Apportionment Change


-



16



16







    Add:   Acquisition Costs


5



-



5







Total

$

239


$

(35)


$

204






















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

















Year Ended December 31, 2015









 Before 



 Income Tax  



 After 









 Tax 



 Impact 



 Tax 







Adjustments:















    Add:   Mark-to-Market Commodity Derivative Contracts Impact

$

668


$

(238)


$

430







    Add:   Impairments of Certain Assets


6,308



(2,183)



4,125







    Less:  Texas Margin Tax Rate Reduction


-



(20)



(20)







    Add:   Legal Settlement - Early Leasehold Termination


19



(6)



13







    Add:   Severance Costs


9



(3)



6







    Add:   Net Losses on Asset Dispositions


9



(4)



5







Total

$

7,013


$

(2,454)


$

4,559






















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















Year Ended December 31, 2014









 Before 



 Income Tax  



 After 









 Tax 



 Impact 



 Tax 







Adjustments:















    Less:  Mark-to-Market Commodity Derivative Contracts Impact

$

(800)


$

285


$

(515)







    Add:   Impairments of Certain Assets


824



(271)



553







    Less:  Net Gains on Asset Dispositions


(508)



21



(487)







    Add:   Tax Expense Related to the Repatriation of Accumulated















                 Foreign Earnings in Future Years


-



250



250







Total

$

(484)


$

285


$

(199)






















 

EOG RESOURCES, INC.

Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total

Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest

Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

(Unaudited; in millions, except ratio data)



















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




















2013


2012


2011


2010


2009


2008

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


















(Calculated Using GAAP Net Income)




































Net Interest Expense (GAAP)

$

235


$

214


$

210


$

130


$

101


$

52

Tax Benefit Imputed (based on 35%) 


(82)



(75)



(74)



(46)



(35)



(18)

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

$

153


$

139


$

136


$

84


$

66


$

34



















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

$

2,197


$

570


$

1,091


$

161


$

547


$

2,437



















Total Stockholders' Equity (GAAP) - (d)   

$

15,418


$

13,285


$

12,641


$

10,232


$

9,998


$

9,015



















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

$

14,352


$

12,963


$

11,437


$

10,115


$

9,507


$

8,003



















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

$

5,909


$

6,312


$

5,009


$

5,223


$

2,797


$

1,897

Less: Cash                                                       


(1,318)



(876)



(616)



(789)



(686)



(331)

Net Debt (Non-GAAP) - (i) 

$

4,591


$

5,436


$

4,393


$

4,434


$

2,111


$

1,566








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