EOG Resources Announces First Quarter 2018 Results

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 May 3, 2018 - 4:17 PM EDT
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EOG Resources Announces First Quarter 2018 Results

HOUSTON, May 3, 2018 /PRNewswire/ --

  • Reports Strong Operating Results 
    • ­Achieves Record Returns on First Quarter Capital Investments
    • U.S. Oil Production Near High End of Target Range
    • ­U.S. Realized Crude Oil Price Exceeds WTI NYMEX Average
    • ­Per-Unit Transportation and DD&A Expenses Below Targets
  • Maintains Full-Year $5.4-$5.8 Billion Exploration and Development Expenditure Target
    • ­On Track to Reduce Well Costs 5 Percent in 2018
  • Reiterates Full-Year 2018 Oil Production Growth Target of 16-20 Percent
  • Targets $3 Billion Debt Reduction and Higher Dividend Growth Rate

EOG Resources, Inc. (NYSE: EOG) (EOG) today reported first quarter 2018 net income of $638.6 million, or $1.10 per share. This compares to first quarter 2017 net income of $28.5 million, or $0.05 per share. 

Adjusted non-GAAP net income for the first quarter 2018 was $689.5 million, or $1.19 per share, compared to adjusted non-GAAP net income of $89.4 million, or $0.15 per share, for the same prior year period.  Higher commodity prices, increased production volumes and overall per-unit cost reductions resulted in increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the first quarter 2018 compared to the first quarter 2017.  Adjusted non-GAAP net income is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude one-time items.  Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Operational Highlights
EOG achieved record returns on new capital investments in the first quarter 2018. The company increased first quarter 2018 crude oil production by 15 percent compared to the first quarter 2017.  EOG maintained its forecast for 16 to 20 percent crude oil growth for full year 2018.  Strong production growth reflects the company's premium drilling strategy and technical advances across its diverse inventory of high-return plays.  EOG defines premium drilling as prospective well locations that will earn a minimum 30 percent direct after-tax rate of return at $40 crude oil and $2.50 natural gas prices.  EOG's prolific Delaware Basin, Eagle Ford and Powder River Basin assets all contributed to growth this quarter.  The company realized an average price for U.S. crude oil sales in the first quarter 2018 of $64.24 per barrel.  This is $1.35 per barrel above the average WTI NYMEX price during the same period.

Overall per-unit operating expenses decreased during the first quarter 2018.  This performance was led by a 21 percent reduction in per-unit depreciation, depletion and amortization (DD&A) expenses compared to the same prior year period.  Per-unit transportation and general and administrative costs also declined during the first quarter 2018.

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

"EOG delivered another sterling performance in the first quarter despite a challenging operating environment," said William R. "Bill" Thomas, Chairman and Chief Executive Officer.  "New capital investments produced record-level rates of return. Our innovative employees executed our game plan with high efficiency to deliver results that met or exceeded expectations while remaining on track to lower costs.  EOG is well positioned to accomplish its full-year plan and generate high-return, disciplined growth in 2018."

Capital Structure and Financial Strategy
At March 31, 2018, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 28 percent.  Considering cash on the balance sheet at the end of the first quarter, EOG's net debt was $5.6 billion for a net debt-to-total capitalization ratio of 25 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG intends to repay bonds as they mature over the next four years, with a goal to reduce total debt outstanding by $3 billion.  In addition, the company is targeting an increase in its historical rate of dividend growth.  Sustainable dividend growth is a distinguishing attribute of EOG.  The company increased its dividend at a 19 percent compound annual rate from 1999 to 2017 without any reductions.  The shift to premium drilling and the recovery in oil prices have increased EOG's after-tax rate of return on new investments to record levels.  With an improving financial condition, EOG now aims to grow its dividend at a higher rate than its historical average. 

"EOG is uniquely positioned to generate strong organic growth, increase return on capital employed, further strengthen the balance sheet and step up cash returns to shareholders," noted Thomas.  "Our objectives to reduce debt outstanding and increase the dividend growth rate reflect the strength of our business model.  The company is capable of withstanding price volatility and well positioned to create significant shareholder value through commodity cycles."

Delaware Basin
In the first quarter 2018, EOG shifted to larger-scale development activity in the Delaware Basin utilizing 19 rigs compared to 13 rigs in 2017.  Seventy new wells began production across multiple targets, although only 14 of these were brought on-line in January.  Activity was focused on further delineating additional targets and testing development patterns in different areas of the basin.

In the Delaware Basin Wolfcamp, EOG completed several notable wells, including the State Magellan 7 22H-28H.  This seven-well package, drilled on 500-foot spacing, was completed with an average treated lateral length of 4,700 feet per well and average 30-day initial production rates per well of 2,200 barrels of oil equivalent per day (Boed), or 1,455 barrels of oil per day (Bopd), 310 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.6 million cubic feet per day (MMcfd) of natural gas. 

In the Delaware Basin First Bone Spring, EOG completed the Beowulf 33 State Com 301H in Lea County, NM with a treated lateral length of 6,900 feet and a 30-day initial production rate of 1,735 Boed, or 1,275 Bopd, 200 Bpd of NGLs and 1.6 MMcfd of natural gas. 

In the Delaware Basin Leonard, EOG completed the Gem 36 State Com 05H and 06H with an average treated lateral length per well of 4,200 feet and average 30-day initial production rates per well of 2,555 Boed, or 1,605 Bopd, 395 Bpd of NGLs and 3.3 MMcfd of natural gas. 

South Texas Eagle Ford and Austin Chalk
EOG's South Texas Eagle Ford continued to generate strong results across the entire extent of its 520,000 net acre position in the crude oil window of the play.  EOG continues to optimize its wells with staggered patterns and enhanced targeting, which is producing premium-level returns even in heavily developed parts of the field.  Wells completed in the first quarter were drilled with an average distance between wells of approximately 300 feet per well.  Lateral lengths are also being extended, primarily in the western half of the field, where lateral lengths averaged 9,200 feet per well in the first quarter.

Notable wells in the first quarter included the Presley Unit 12H-14H, a three-well package in Karnes County, TX with an average treated lateral length of 6,800 feet per well and average 30-day initial production rates per well of 3,360 Boed, or 2,670 Bopd, 350 Bpd of NGLs and 2.0 MMcfd of natural gas.  On the western side of the Eagle Ford in Atascosa County, TX, EOG completed the Watermelon Unit 2H and 3H with an average treated lateral length of 12,400 feet per well and average 30-day initial production rates per well of 1,680 Boed, or 1,490 Bopd, 100 Bpd of NGLs and 0.6 MMcfd of natural gas.

Development continued in the Austin Chalk, with the first quarter drilling program highlighted by the Elbrus 101H and 102H, with an average treated lateral length of 4,600 feet per well and average 30-day initial production rates per well of 4,305 Boed, or 2,980 Bopd, 670 Bpd of NGLs and 3.9 MMcfd of natural gas. 

Rockies and the Bakken
During the first quarter, EOG continued to develop its premium Powder River Basin and DJ Basin positions and began its 2018 drilling program in the Bakken.  The company continued to lower well costs in its Rockies plays by improving drilling and completion times along with other efficiency improvements. 

EOG brought 12 wells on line in the Powder River Basin during the first quarter 2018, including nine targeting the Turner formation.  Notably, the Flatbow 16-36H–18-36H, a three-well package in the Powder River Turner, was completed with an average treated lateral length of 3,900 feet per well and average 30-day initial production rates per well of 1,325 Boed, or 775 Bopd, 190 Bpd of NGLs and 2.2 MMcfd of natural gas.  These short-lateral wells had an average cost of $2.9 million per well.

In the DJ Basin, EOG began production in the first quarter from 12 wells.  In particular, a four-well package of DJ Basin Codell wells, the Big Sandy 529, 552, 553 and 554-1423H, was completed with an average treated lateral length of 9,500 feet per well and average 30-day initial production rates per well of 1,340 Boed, or 1,120 Bopd, 135 Bpd of NGLs and 0.5 MMcfd of natural gas.  These wells were drilled in an average of 4.2 days per well with an average cost of $3.5 million per well.

In the North Dakota Bakken, EOG drilled 4 wells in the first quarter and deferred completions until later in 2018.   

Woodford Oil Window
EOG continued development of its new oil play in the Woodford formation of the Eastern Anadarko Basin.  In the first quarter, EOG increased drilling operations to three rigs and added a fourth rig in April.  Production began from one well during the quarter.  The Terri 1621 #1H was completed with a treated lateral length of 10,200 feet and a 30-day initial production rate of 1,395 Boed, or 1,140 Bopd, 165 Bpd of NGLs and 0.5 MMcfd of natural gas.

Hedging Activity
During the first quarter ended March 31, 2018, EOG entered into crude oil financial price swap contracts.  A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables. 

Conference Call May 4, 2018
EOG's first 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, May 4, 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

March 31,

2018

2017




Operating Revenues and Other

$

3,681.2

$

2,610.6

Net Income 

$

638.6

$

28.5

Net Income Per Share 




        Basic

$

1.11

$

0.05

        Diluted

$

1.10

$

0.05

Average Number of Common Shares




        Basic

575.8

573.9

        Diluted

579.7

578.6










Summary Income Statements

(Unaudited; in thousands, except per share data)





Three Months Ended

March 31,

2018

2017

Operating Revenues and Other


        Crude Oil and Condensate

$

2,101,308

$

1,430,061

        Natural Gas Liquids

221,415

153,444

        Natural Gas

299,766

230,602

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

(59,771)

62,020

        Gathering, Processing and Marketing

1,101,822

726,537

        Losses on Asset Dispositions, Net

(14,969)

(16,758)

        Other, Net

31,591

24,659

               Total

3,681,162

2,610,565

Operating Expenses




        Lease and Well

300,064

255,777

        Transportation Costs

176,957

178,714

        Gathering and Processing Costs

101,345

38,144

        Exploration Costs

34,836

56,894

        Impairments 

64,609

193,187

        Marketing Costs

1,106,390

736,536

        Depreciation, Depletion and Amortization

748,591

816,036

        General and Administrative

94,698

97,238

        Taxes Other Than Income

179,084

130,293

               Total

2,806,574

2,502,819




Operating Income 

874,588

107,746




Other Income, Net

727

3,151




Income Before Interest Expense and Income Taxes

875,315

110,897




Interest Expense, Net

61,956

71,515




Income Before Income Taxes

813,359

39,382




Income Tax Provision

174,770

10,865




Net Income 

$

638,589

$

28,517




Dividends Declared per Common Share

$

0.1850

$

0.1675

 

EOG RESOURCES, INC.

Operating Highlights

(Unaudited)





Three Months Ended

March 31,

2018

2017

Wellhead Volumes and Prices

Crude Oil and Condensate Volumes (MBbld) (A)

      United States

359.7

312.5

      Trinidad

0.9

0.8

      Other International (B)

2.7

2.4

            Total

363.3

315.7




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




      United States

$

64.24

$

50.38

      Trinidad

54.86

41.56

      Other International (B)

71.61

47.77

            Composite

64.27

50.34




Natural Gas Liquids Volumes (MBbld) (A)




      United States

100.6

78.8

      Other International (B)

-

-

            Total

100.6

78.8




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




      United States

$

24.46

$

21.63

      Other International (B)

-

-

            Composite

24.46

21.63




Natural Gas Volumes (MMcfd) (A)




      United States

853

728

      Trinidad

293

308

      Other International (B)

30

22

            Total

1,176

1,058




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




      United States

$

2.76

$

2.32

      Trinidad

2.88

2.57

      Other International (B)

4.36

3.76

            Composite

2.83

(D)

2.42




Crude Oil Equivalent Volumes (MBoed) (E)




      United States 

602.5

512.6

      Trinidad

49.8

52.2

      Other International (B)

7.6

5.9

            Total

659.9

570.7




Total MMBoe (E)

59.4

51.4


(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 March 31, 2018).

(D) Includes a positive revenue adjustment of $0.41 per Mcf 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 March 31, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for 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)





March 31,

December 31,

2018

2017

ASSETS

Current Assets




     Cash and Cash Equivalents

$

816,094

$

834,228

     Accounts Receivable, Net

1,702,100

1,597,494

     Inventories

584,729

483,865

     Assets from Price Risk Management Activities

761

7,699

     Income Taxes Receivable

262,789

113,357

     Other

218,624

242,465

            Total

3,585,097

3,279,108




Property, Plant and Equipment




     Oil and Gas Properties (Successful Efforts Method)

53,854,438

52,555,741

     Other Property, Plant and Equipment

4,082,781

3,960,759

            Total Property, Plant and Equipment

57,937,219

56,516,500

     Less:  Accumulated Depreciation, Depletion and Amortization

(31,561,571)

(30,851,463)

            Total Property, Plant and Equipment, Net

26,375,648

25,665,037

Deferred Income Taxes

18,182

17,506

Other Assets

761,590

871,427

Total Assets

$

30,740,517

$

29,833,078




LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities




     Accounts Payable

$

1,915,651

$

1,847,131

     Accrued Taxes Payable

179,646

148,874

     Dividends Payable

106,521

96,410

     Liabilities from Price Risk Management Activities

84,128

50,429

     Current Portion of Long-Term Debt

363,155

356,235

     Other

187,657

226,463

            Total

2,836,758

2,725,542










Long-Term Debt

6,071,604

6,030,836

Other Liabilities

1,301,938

1,275,213

Deferred Income Taxes

3,689,578

3,518,214

Commitments and Contingencies










Stockholders' Equity




     Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 
        579,272,616 Shares Issued at March 31, 2018 and 578,827,768
        Shares Issued at December 31, 2017  

205,793

205,788

     Additional Paid in Capital

5,569,194

5,536,547

     Accumulated Other Comprehensive Loss

(14,289)

(19,297)

     Retained Earnings

11,125,051

10,593,533

     Common Stock Held in Treasury, 459,990 Shares at March 31, 2018 and 350,961 Shares at December 31, 2017

(45,110)

(33,298)

            Total Stockholders' Equity

16,840,639

16,283,273

Total Liabilities and Stockholders' Equity

$

30,740,517

$

29,833,078

 

EOG RESOURCES, INC.

Summary Statements of Cash Flows

(Unaudited; in thousands)





Three Months Ended

March 31,

2018

2017

Cash Flows from Operating Activities




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




     Net Income

$

638,589

$

28,517

     Items Not Requiring (Providing) Cash




            Depreciation, Depletion and Amortization

748,591

816,036

            Impairments 

64,609

193,187

            Stock-Based Compensation Expenses

35,486

30,460

            Deferred Income Taxes

171,362

694

            Losses on Asset Dispositions, Net

14,969

16,758

            Other, Net

2,013

(3,052)

     Mark-to-Market Commodity Derivative Contracts




            Total (Gains) Losses

59,771

(62,020)

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

(21,965)

1,912

     Other, Net

(478)

(428)

     Changes in Components of Working Capital and Other Assets and Liabilities




            Accounts Receivable

(109,654)

28,688

            Inventories

(106,799)

24,736

            Accounts Payable

53,652

20,426

            Accrued Taxes Payable

21,950

(38,613)

            Other Assets

(8,863)

(44,677)

            Other Liabilities

(29,055)

(51,251)

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

17,988

(63,324)

Net Cash Provided by Operating Activities

1,552,166

898,049




Investing Cash Flows




     Additions to Oil and Gas Properties

(1,365,111)

(912,227)

     Additions to Other Property, Plant and Equipment

(76,100)

(34,336)

     Proceeds from Sales of Assets

2,829

46,812

     Changes in Components of Working Capital Associated with Investing Activities

(18,045)

63,324

Net Cash Used in Investing Activities

(1,456,427)

(836,427)




Financing Cash Flows




     Dividends Paid

(97,026)

(96,707)

     Treasury Stock Purchased

(16,776)

(18,628)

     Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

1,453

2,356

     Repayment of Capital Lease Obligation

(1,671)

(1,619)

     Changes in Working Capital Associated with Financing Activities

57

-

Net Cash Used in Financing Activities

(113,963)

(114,598)




Effect of Exchange Rate Changes on Cash

90

(353)




Decrease in Cash and Cash Equivalents

(18,134)

(53,329)

Cash and Cash Equivalents at Beginning of Period

834,228

1,599,895

Cash and Cash Equivalents at End of Period

$

816,094

$

1,546,566

 

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 periods ended March 31, 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 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 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 

March 31, 2018

March 31, 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)

$813,359

$(174,770)

$638,589

$      1.10

$  39,382

$(10,865)

$28,517

$      0.05

Adjustments:














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

59,771

(13,166)

46,605

0.08

(62,020)

22,191

(39,829)

(0.07)

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

(21,965)

4,838

(17,127)

(0.03)

1,912

(684)

1,228

-

Add:  Net Losses on Asset Dispositions

14,969

(3,324)

11,645

0.02

16,758

(5,736)

11,022

0.02

Add:  Impairments

20,876

(4,598)

16,278

0.03

137,751

(49,287)

88,464

0.15

Less:  Tax Reform Impact

-

(6,524)

(6,524)

(0.01)

-

-

-

-

Adjustments to Net Income 

73,651

(22,774)

50,877

0.09

94,401

(33,516)

60,885

0.10














Adjusted Net Income (Non-GAAP)

$887,010

$(197,544)

$689,466

$      1.19

$133,783

$(44,381)

$89,402

$      0.15














Average Number of Common Shares (GAAP)














       Basic





575,775






573,935

       Diluted





579,726






578,593

 

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 periods ended March 31, 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 three months ended March 31, 2018.  EOG management uses this information for comparative purposes within the industry.







Three Months Ended

March 31,

2018

2017





Net Cash Provided by Operating Activities (GAAP)

$

1,552,166

$

898,049





Adjustments:





Exploration Costs (excluding Stock-Based Compensation Expenses) 

27,936

50,734

Other Non-Current Income Taxes - Net Receivable

118,921

-

Changes in Components of Working Capital and Other Assets and Liabilities





Accounts Receivable

109,654

(28,688)

Inventories

106,799

(24,736)

Accounts Payable

(53,652)

(20,426)

Accrued Taxes Payable

(21,950)

38,613

Other Assets

8,863

44,677

Other Liabilities

29,055

51,251

Changes in Components of Working Capital Associated with 





Investing and Financing Activities

(17,988)

63,324


Discretionary Cash Flow (Non-GAAP)

$

1,859,804

$

1,072,798





Discretionary Cash Flow (Non-GAAP) - Percentage Increase

73%























Discretionary Cash Flow (Non-GAAP)

$

1,859,804


Less:  





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

(1,477,830)


Dividends Paid (GAAP) 

(97,026)


Free Cash Flow (Non-GAAP)

$

284,948
















(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months ended March 31, 2018:





Total Expenditures (GAAP)

$

1,546,641


Less:  





          Asset Retirement Costs

(12,100)


          Non-Cash Acquisition Costs of Other Property, Plant and Equipment

(47,635)


          Non-Cash Acquisition Costs of Unproved Properties

(8,809)


          Acquisition Costs of Proved Properties

(267)


Total Cash Expenditures Excluding Acquisitions (Non-GAAP) 

$

1,477,830


 

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 periods ended March 31, 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 net 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

March 31,

2018

2017




Net Income (GAAP)

$

638,589

$

28,517




Adjustments:




     Interest Expense, Net

61,956

71,515

     Income Tax Provision 

174,770

10,865

     Depreciation, Depletion and Amortization

748,591

816,036

     Exploration Costs

34,836

56,894

     Impairments 

64,609

193,187

             EBITDAX (Non-GAAP)

1,723,351

1,177,014

     Total (Gains) Losses on MTM Commodity Derivative Contracts  

59,771

(62,020)

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

(21,965)

1,912

     Losses on Asset Dispositions, Net

14,969

16,758




Adjusted EBITDAX (Non-GAAP)

$

1,776,126

$

1,133,664




Adjusted EBITDAX (Non-GAAP) - Percentage Increase

57%


 

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

March 31,

December 31,

2018

2017




Total Stockholders' Equity - (a)

$

16,841

$

16,283




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

6,435

6,387

Less: Cash 

(816)

(834)

Net Debt (Non-GAAP) - (c)

5,619

5,553




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

$

23,276

$

22,670




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

$

22,460

$

21,836




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

28%

28%




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

25%

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 April 26, 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 May 31, 2018 (closed)

15,000

$           1.063

June 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 April 26, 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 May 31, 2018 (closed)

37,000

$           3.818

June 1, 2018 through December 31, 2018 

37,000

3.818










Presented below is a comprehensive summary of EOG's crude oil price swap contracts through April 26, 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 March 31, 2018 (closed)

134,000

$           60.04

April 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 April 26, 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 May 31, 2018 (closed)

35,000

$             3.00

June 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 April 26, 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 May 31, 2018 (closed)

120,000

$                3.38

96,000

$             2.94

June 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.

Second Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing










     (a)  Second Quarter and Full Year 2018 Forecast










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










     (b)  Benchmark Commodity Pricing










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










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
















Estimated Ranges










(Unaudited)






2Q 2018

Full Year 2018

Daily Sales Volumes










     Crude Oil and Condensate Volumes (MBbld)










          United States

374.0

-

382.0

387.0

-

401.0

          Trinidad

0.4

-

0.6

0.4

-

0.6

          Other International

0.0

-

6.0

2.0

-

4.0

               Total

374.4

-

388.6

389.4

-

405.6










     Natural Gas Liquids Volumes (MBbld)










               Total

100.0

-

110.0

100.0

-

110.0










     Natural Gas Volumes (MMcfd)










          United States

870

-

910

900

-

950

          Trinidad

280

-

300

250

-

290

          Other International

25

-

35

28

-

38

               Total

1,175

-

1,245

1,178

-

1,278










     Crude Oil Equivalent Volumes (MBoed)  










          United States

619.0

-

643.7

637.0

-

669.3

          Trinidad

47.1

-

50.6

42.1

-

48.9

          Other International

4.2

-

11.9

6.7

-

10.3

               Total

670.3

-

706.2

685.8

-

728.5
















Estimated Ranges










(Unaudited)





2Q 2018

Full Year 2018

Operating Costs










     Unit Costs ($/Boe)










          Lease and Well

$

4.50

-

$

4.90

$

4.20

-

$

4.80

          Transportation Costs

$

2.90

-

$

3.40

$

2.75

-

$

3.25

          Depreciation, Depletion and Amortization

$

13.15

-

$

13.55

$

13.00

-

$

13.40










Expenses ($MM)










     Exploration, Dry Hole and Impairment

$

100

-

$

120

$

375

-

$

425

     General and Administrative

$

100

-

$

110

$

415

-

$

445

     Gathering and Processing 

$

110

-

$

120

$

430

-

$

470

     Capitalized Interest

$

5

-

$

6

$

19

-

$

23

     Net Interest

$

62

-

$

65

$

244

-

$

248










Taxes Other Than Income (% of Wellhead Revenue)

6.5%

-

6.9%

6.5%

-

6.9%










Income Taxes










     Effective Rate 

20%

-

25%

20%

-

25%

     Current Tax (Benefit) / Expense ($MM)

$

(90)

-

$

(55)

$

(350)

-

$

(310)










Capital Expenditures (Excluding Acquisitions, $MM)










     Exploration and Development, Excluding Facilities





$

4,500

-

$

4,800

     Exploration and Development Facilities





$

600

-

$

650

     Gathering, Processing and Other





$

300

-

$

350










Pricing - (Refer to Benchmark Commodity Pricing in text)










     Crude Oil and Condensate ($/Bbl)










          Differentials










               United States - above (below) WTI

$

(1.50)

-

$

0.50

$

(1.25)

-

$

0.75

               Trinidad - above (below) WTI

$

(11.00)

-

$

(9.00)

$

(11.00)

-

$

(9.00)

               Other International - above (below) WTI

$

2.00

-

$

4.00

$

0.00

-

$

6.00










     Natural Gas Liquids










          Realizations as % of WTI

32%

-

38%

32%

-

38%










     Natural Gas ($/Mcf)










          Differentials










               United States - above (below) NYMEX Henry Hub

$

(0.70)

-

$

(0.30)

$

(0.60)

-

$

0.00










          Realizations










               Trinidad

$

2.30

-

$

2.70

$

2.15

-

$

2.75

               Other International

$

4.15

-

$

4.65

$

4.00

-

$

5.00










Definitions










$/Bbl         U.S. Dollars per barrel

$/Boe        U.S. Dollars per barrel of oil equivalent

$/Mcf         U.S. Dollars per thousand cubic feet

$MM          U.S. Dollars in millions

MBbld       Thousand barrels per day

MBoed      Thousand barrels of oil equivalent per day

MMcfd       Million cubic feet per day

NYMEX     U.S. New York Mercantile Exchange

WTI           West Texas Intermediate

 

EOG RESOURCES, INC.

First 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

58

53

5,900

1,335

250

2.1

1,925

Bone Spring

9

8

5,900

1,195

190

1.6

1,645

Leonard

3

3

4,300

1,640

335

2.8

2,430













Powder River Basin Turner

9

8

6,100

675

180

2.1

1,210













DJ Basin Codell

12

9

9,200

895

95

0.4

1,055













South Texas Eagle Ford

72

65

6,900

1,325

150

0.9

1,620













South Texas Austin Chalk

10

8

4,600

1,960

400

2.3

2,750













(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.

 

Cision View original content:http://www.prnewswire.com/news-releases/eog-resources-announces-first-quarter-2018-results-300642509.html

SOURCE EOG Resources, Inc.


Source: PR Newswire (May 3, 2018 - 4:17 PM EDT)

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