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EOG Resources Reports Third Quarter 2020 Results; Adds Premium Natural Gas Play in South Texas; Provides Three-Year Outlook

HOUSTON, Nov. 5, 2020 /PRNewswire/ --

  • Identified 21 Tcf Net Resource Potential and 1,250 Net Premium Locations in New South Texas Natural Gas Play
  • Added a Total of 1,400 Net Premium Locations to Drilling Inventory Which Now Totals 11,500 Locations
  • Generated $1.2 Billion Net Cash Provided by Operating Activities and Significant Free Cash Flow
  • Capital Expenditures 23% Below Target and Crude Oil Production 2% Above Target
  • Per-Unit Cash Operating Costs Below Targets
  • Introduced Three-Year Outlook with 70-80% Cash Flow Reinvestment

EOG Resources, Inc. (EOG) today reported a third quarter 2020 net loss of $42 million, or $0.07 per share, compared with third quarter 2019 net income of $615 million, or $1.06 per share.

Adjusted non-GAAP net income for the third quarter 2020 was $252 million, or $0.43 per share, compared with adjusted non-GAAP net income of $654 million, or $1.13 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Third Quarter 2020 Review
EOG continued to respond aggressively to adverse market conditions by sharply lowering operating and capital costs as well as deferring production volumes to future periods. Reductions to operating costs were offset by lower commodity prices and production volumes, resulting in lower earnings in the third quarter 2020 compared with the same prior year period. Realized crude oil prices were $40.15 per barrel in the third quarter, down 29 percent from the same prior year period, while natural gas prices declined 21 percent, to $1.68 per thousand cubic feet. These declines were partially offset by an increase in natural gas liquids prices in the third quarter to $14.34 per barrel, up 13 percent compared with the same prior year period.

Compared with the third quarter 2019, total company crude oil volumes were 19 percent lower, at 377,600 barrels of oil per day (Bopd). Natural gas liquids production was one percent lower and natural gas volumes were 13 percent lower, contributing to 14 percent lower total company daily production. EOG continued to return shut-in wells to production during the third quarter, and nearly all shut-in wells were back on production by the end of September. On average, 28,000 Bopd was shut-in during the third quarter. EOG also began initial production from approximately 100 net new wells in the third quarter, after deferring such activity earlier in the year in response to lower oil prices.

Lease and well costs declined 24 percent on a per-unit basis compared with the same prior year period, driving an overall reduction in per-unit operating costs. Most of the lease and well cost savings were based on sustainable efficiency improvements in well-site maintenance, equipment repair, managing offset completions and other production operations.

Net cash provided by operating activities was $1.2 billion. Excluding changes in working capital and certain other items, EOG generated $1.3 billion of discretionary cash flow. The company incurred total expenditures of $646 million, including $499 million of capital expenditures before acquisitions, non–cash transactions and asset retirement costs, resulting in $762 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

"Our operational execution continues to be excellent," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "I'm grateful to all EOG employees during these unusual times. We continue to exceed expectations by optimizing production volumes and reducing costs while maintaining our strong safety and environmental performance.

"Notably, we are not playing defense in the current challenging environment. In fact, the opposite is true: we are aggressively moving EOG forward, advancing new plays, identifying innovative solutions to lower costs and improve well productivity, sharpening our technological edge and further demonstrating our commitment to sustainability. All of this is driven from the bottom up by a decentralized organization and a unique culture. This year more than ever, we are focused on investing in our people and enhancing our culture to sustain our competitive advantage and enable EOG to play an increasingly vital role in meeting the long-term global energy needs."

New South Texas Natural Gas Play and Premium Inventory Update
EOG has made a large natural gas resource play discovery on its Dorado prospect located in Webb County, Texas. A total of 21 trillion cubic feet (Tcf) of estimated net resource potential is contained in 700 feet of stacked pay in the Austin Chalk and Eagle Ford Shale formations. The company has identified an initial 1,250 net premium drilling locations across its 163,000 net acre position in the core of the play. EOG has drilled 17 wells in the Dorado play since January 2019, including five wells targeting the Austin Chalk and 12 wells targeting the Upper and Lower Eagle Ford.

The Austin Chalk formation has an estimated net resource potential of 9.5 Tcf of natural gas. EOG has identified 530 net premium drilling locations in the Austin Chalk. The prolific Austin Chalk wells generate rates of return that are competitive with EOG's large inventory of premium oil plays. The rates of return are supported by low cash operating costs and proximity to several natural gas markets with options for LNG and pipeline export pricing. In addition, EOG plans to apply its latest water and emissions management technology to minimize the environmental footprint of its development activities.

The five initial Austin Chalk wells produced an average of 3.5 billion cubic feet (Bcf) of natural gas per well in the first year of production, with an average lateral length of 6,600 feet per well. EOG expects to complete approximately 15 wells in the Austin Chalk in 2021. A typical Austin Chalk well is expected to recover 22 Bcf of natural gas, or 18 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $7.0 million per well.

The company has identified additional net resource potential of 11.5 Tcf and 720 net premium drilling locations in the Lower and Upper Eagle Ford, which underlies the Austin Chalk in the same area. Wells targeting the Eagle Ford also generate strong premium rates of return, supported by low drilling costs and shared infrastructure with the Austin Chalk wells.

The first 12 wells targeting the Eagle Ford produced an average of 2.8 Bcf of natural gas per well in the first year of production, with an average lateral length of 7,700 feet per well. A typical Eagle Ford well is expected to recover 19 Bcf of natural gas, or 16 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $6.5 million per well.

Including the Dorado locations, EOG added 1,400 net premium drilling locations to its undrilled premium inventory in the third quarter 2020. Taking into account wells drilled over the past year and updated location counts across its portfolio, EOG's premium inventory now totals approximately 11,500 net locations.

"Our new South Texas natural gas play is the latest example of EOG's sustainable business model of organic exploration-driven resource expansion," Thomas said. "The addition of Dorado to EOG's diverse portfolio of premium plays improves the financial profile of EOG by every measure. It also allows us to diversify capital deployment throughout the organization and across our assets. We believe this prolific new discovery represents the lowest-cost natural gas play in the U.S., which will be both operationally efficient and have a small environmental footprint. With 21 Tcf of net resource potential captured by EOG in the heart of the play, it is also one of the largest. Dorado competes today with EOG's premium oil plays, and we expect it to move rapidly into the top tier of our inventory as development unfolds. This is just the latest example of how EOG continues to organically improve."

Capital Allocation Outlook
Over the next three years, EOG's goal is to continue improving reinvestment returns, lowering per-unit operating costs and generating strong free cash flow to support a growing sustainable dividend while further strengthening its balance sheet. The company anticipates the current imbalance in the global crude oil market is likely to extend into 2021, and therefore expects to maintain its crude oil production at approximately the same level as the fourth quarter 2020. Assuming a balanced crude oil market after 2021, EOG expects to reinvest 70 to 80 percent of its discretionary cash flow and generate up to 10 percent compound annual crude oil production growth in 2022 and 2023 at a $50 West Texas Intermediate crude oil price and using the company's current inventory of premium locations. At higher oil prices, EOG expects to maintain the same growth rate of up to 10 percent per year. Priorities for the allocation of additional free cash flow include sustainable dividend growth, debt reduction, the return of additional cash to shareholders and low-cost property acquisitions.

"Our new three-year outlook provides visibility into the momentum we have built the last four years since the introduction of our premium return criteria," Thomas said. "EOG's long-term strategy and capital allocation priorities remain consistent. We are focused on high-return reinvestment in our growing stable of premium plays, which continues to improve in quality and drives increasing capital efficiency. With our disciplined capital allocation, we expect free cash flow growth, which will support sustainable dividend growth and further strengthen the balance sheet. Returning additional cash to shareholders also becomes more likely as oil prices continue to recover. Altogether, this balanced strategy leverages the competitive strengths of EOG and maximizes total shareholder value."

Financial Review
At September 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $3.1 billion of cash on the balance sheet at the end of the third quarter, EOG's net debt-to-total capitalization ratio was 12 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of September 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

EOG divested its assets in the Marcellus Shale effective September 1, 2020 for proceeds of approximately $130 million. Current production from the divested assets is approximately 40 million cubic feet of natural gas per day and there were no premium locations associated with the assets.

Third Quarter 2020 Results Webcast
Friday, November 6, 2020, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors

About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.

Investor Contacts
David Streit  713-571-4902
Neel Panchal  713-571-4884

Media and Investor Contact
Kimberly Ehmer  713-571-4676

Category: Earnings

This press release may include 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, capital expenditures, 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, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance 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, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position.  Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry.  Any such 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 such measures and estimates.  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 (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
  • 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;
  • security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
  • the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, 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 any changes or other actions which may result from the recent U.S. elections and including tax laws and regulations; climate change and other 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 affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and 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 drilling, completing and operating 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 tubulars) 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, storage 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;
  • the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
  • geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, 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; and
  • the other factors described under ITEM 1A, Risk Factors, on pages 13 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 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 or 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 or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources 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, 2019, 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.

 

Income Statements

 

In thousands of USD, except per share data (Unaudited)

               
 

3Q 2020

 

3Q 2019

 

YTD 2020

 

YTD 2019

Operating Revenues and Other

       

Crude Oil and Condensate

1,394,622

   

2,418,989

   

4,074,747

   

7,148,258

 

Natural Gas Liquids

184,771

   

164,736

   

439,215

   

569,748

 

Natural Gas

183,790

   

269,625

   

535,250

   

874,489

 

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

(3,978)

   

85,902

   

1,075,433

   

242,622

 

Gathering, Processing and Marketing

538,955

   

1,334,450

   

1,940,387

   

4,121,490

 

Gains (Losses) on Asset Dispositions, Net

(70,976)

   

(523)

   

(41,283)

   

3,650

 

Other, Net

18,300

   

30,276

   

42,801

   

99,470

 

Total

2,245,484

   

4,303,455

   

8,066,550

   

13,059,727

 
               

Operating Expenses

             

Lease and Well

227,473

   

348,883

   

802,478

   

1,032,455

 

Transportation Costs

180,257

   

199,365

   

540,281

   

549,988

 

Gathering and Processing Costs

114,790

   

127,549

   

340,039

   

351,487

 

Exploration Costs

38,413

   

34,540

   

105,373

   

103,386

 

Dry Hole Costs

12,604

   

24,138

   

13,063

   

28,001

 

Impairments

78,990

   

105,275

   

1,957,340

   

289,761

 

Marketing Costs

521,351

   

1,343,293

   

2,074,788

   

4,114,265

 

Depreciation, Depletion and Amortization

823,050

   

953,597

   

2,529,789

   

2,790,496

 

General and Administrative

124,460

   

135,758

   

370,588

   

364,210

 

Taxes Other Than Income

126,810

   

203,098

   

364,489

   

600,418

 

Total

2,248,198

   

3,475,496

   

9,098,228

   

10,224,467

 
               

Operating Income (Loss)

(2,714)

   

827,959

   

(1,031,678)

   

2,835,260

 

Other Income, Net

3,401

   

9,118

   

17,009

   

23,233

 

Income (Loss) Before Interest Expense and Income Taxes

687

   

837,077

   

(1,014,669)

   

2,858,493

 

Interest Expense, Net

53,242

   

39,620

   

152,145

   

144,434

 

Income (Loss) Before Income Taxes

(52,555)

   

797,457

   

(1,166,814)

   

2,714,059

 

Income Tax Provision (Benefit)

(10,088)

   

182,335

   

(224,776)

   

615,670

 

Net Income (Loss)

(42,467)

   

615,122

   

(942,038)

   

2,098,389

 
               

Dividends Declared per Common Share

0.3750

   

0.2875

   

1.1250

   

0.7950

 

Net Income (Loss) Per Share

             

Basic

(0.07)

   

1.06

   

(1.63)

   

3.63

 

Diluted

(0.07)

   

1.06

   

(1.63)

   

3.61

 

Average Number of Common Shares

             

Basic

579,055

   

577,839

   

578,740

   

577,498

 

Diluted

579,055

   

581,271

   

578,740

   

581,190

 

 

Wellhead Volumes and Prices

 

(Unaudited)

 

3Q 2020

 

3Q 2019

 

% Change

 

YTD 2020

 

YTD 2019

 

% Change

                       

Crude Oil and Condensate Volumes (MBbld) (A)

                 

United States

376.6

   

463.2

   

-19

%

 

396.6

   

451.2

   

-12

%

Trinidad

1.0

   

0.8

   

25

%

 

0.5

   

0.7

   

-29

%

Other International (B)

   

0.1

   

-100

%

 

0.2

   

0.1

   

100

%

Total

377.6

   

464.1

   

-19

%

 

397.3

   

452.0

   

-12

%

                       

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

                     

United States

40.19

   

56.67

   

-29

%

 

37.45

   

57.95

   

-35

%

Trinidad

25.41

   

48.36

   

-47

%

 

26.35

   

47.26

   

-44

%

Other International (B)

25.29

   

59.87

   

-58

%

 

45.09

   

58.43

   

-23

%

Composite

40.15

   

56.66

   

-29

%

 

37.44

   

57.93

   

-35

%

                       

Natural Gas Liquids Volumes (MBbld) (A)

                     

United States

140.1

   

141.3

   

-1

%

 

134.2

   

130.8

   

3

%

Other International (B)

   

       

   

     

Total

140.1

   

141.3

   

-1

%

 

134.2

   

130.8

   

3

%

                       

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

                     

United States

14.34

   

12.67

   

13

%

 

11.95

   

15.96

   

-25

%

Other International (B)

   

       

   

     

Composite

14.34

   

12.67

   

13

%

 

11.95

   

15.96

   

-25

%

                       

Natural Gas Volumes (MMcfd) (A)

                     

United States

1,008

   

1,079

   

-7

%

 

1,029

   

1,043

   

-1

%

Trinidad

151

   

260

   

-42

%

 

175

   

267

   

-34

%

Other International (B)

31

   

34

   

-9

%

 

34

   

36

   

-6

%

Total

1,190

   

1,373

   

-13

%

 

1,238

   

1,346

   

-8

%

                       

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

                     

United States

1.49

   

1.97

   

-25

%

 

1.38

   

2.23

   

-38

%

Trinidad

2.35

   

2.52

   

-7

%

 

2.20

   

2.71

   

-19

%

Other International (B)

4.73

   

4.25

   

11

%

 

4.45

   

4.29

   

4

%

Composite

1.68

   

2.13

   

-21

%

 

1.58

   

2.38

   

-34

%

                       

Crude Oil Equivalent Volumes (MBoed) (D)

                     

United States

684.7

   

784.3

   

-13

%

 

702.3

   

755.8

   

-7

%

Trinidad

26.2

   

44.1

   

-41

%

 

29.8

   

45.1

   

-34

%

Other International (B)

5.1

   

5.8

   

-12

%

 

5.7

   

6.2

   

-8

%

Total

716.0

   

834.2

   

-14

%

 

737.8

   

807.1

   

-9

%

                       

Total MMBoe (D)

65.9

   

76.7

   

-14

%

 

202.2

   

220.3

   

-8

%

                       

(A)

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

(B)

Other International includes EOG's 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 in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2020).

(D)

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.

 

Balance Sheets

 

In thousands of USD, except share data (Unaudited)

 

September 30,

 

December 31,

 

2020

 

2019

Current Assets

     

Cash and Cash Equivalents

3,065,556

   

2,027,972

 

Accounts Receivable, Net

1,134,346

   

2,001,658

 

Inventories

668,541

   

767,297

 

Assets from Price Risk Management Activities

18,417

   

1,299

 

Income Taxes Receivable

3,182

   

151,665

 

Other

205,015

   

323,448

 

Total

5,095,057

   

5,273,339

 
 

Property, Plant and Equipment

     

Oil and Gas Properties (Successful Efforts Method)

64,020,452

   

62,830,415

 

Other Property, Plant and Equipment

4,402,091

   

4,472,246

 

Total Property, Plant and Equipment

68,422,543

   

67,302,661

 

Less:  Accumulated Depreciation, Depletion and Amortization

(39,789,537)

   

(36,938,066)

 

Total Property, Plant and Equipment, Net

28,633,006

   

30,364,595

 

Deferred Income Taxes

1,916

   

2,363

 

Other Assets

1,344,039

   

1,484,311

 

Total Assets

35,074,018

   

37,124,608

 
 

Current Liabilities

     

Accounts Payable

1,245,029

   

2,429,127

 

Accrued Taxes Payable

267,245

   

254,850

 

Dividends Payable

217,334

   

166,273

 

Liabilities from Price Risk Management Activities

23,486

   

20,194

 

Current Portion of Long-Term Debt

770,831

   

1,014,524

 

Current Portion of Operating Lease Liabilities

255,357

   

369,365

 

Other

240,760

   

232,655

 

Total

3,020,042

   

4,486,988

 
       

Long-Term Debt

4,949,902

   

4,160,919

 

Other Liabilities

2,151,092

   

1,789,884

 

Deferred Income Taxes

4,804,656

   

5,046,101

 

Commitments and Contingencies

     
       

Stockholders' Equity

     

Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,668,294
Shares Issued at September 30, 2020 and 582,213,016 Shares Issued at
December 31, 2019

205,837

   

205,822

 

Additional Paid in Capital

5,916,213

   

5,817,475

 

Accumulated Other Comprehensive Loss

(7,930)

   

(4,652)

 

Retained Earnings

14,051,197

   

15,648,604

 

Common Stock Held in Treasury, 322,591 Shares at September 30, 2020 and
298,820 Shares at December 31, 2019

(16,991)

   

(26,533)

 

Total Stockholders' Equity

20,148,326

   

21,640,716

 

Total Liabilities and Stockholders' Equity

35,074,018

   

37,124,608

 

 

Cash Flows Statements

 

In thousands of USD (Unaudited)

 

3Q 2020

 

3Q 2019

 

YTD 2020

 

YTD 2019

Cash Flows from Operating Activities

             

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

     Activities:

             

Net Income (Loss)

(42,467)

   

615,122

   

(942,038)

   

2,098,389

 

Items Not Requiring (Providing) Cash

             

Depreciation, Depletion and Amortization

823,050

   

953,597

   

2,529,789

   

2,790,496

 

Impairments

78,990

   

105,275

   

1,957,340

   

289,761

 

Stock-Based Compensation Expenses

33,811

   

54,670

   

113,454

   

132,323

 

Deferred Income Taxes

(33,311)

   

184,282

   

(241,003)

   

508,576

 

(Gains) Losses on Asset Dispositions, Net

70,976

   

523

   

41,283

   

(3,650)

 

Other, Net

1,465

   

(1,284)

   

1,636

   

4,155

 

Dry Hole Costs

12,604

   

24,138

   

13,063

   

28,001

 

Mark-to-Market Commodity Derivative Contracts

             

Total (Gains) Losses

3,978

   

(85,902)

   

(1,075,433)

   

(242,622)

 

Net Cash Received from Settlements of Commodity Derivative
     Contracts

275,133

   

108,418

   

998,894

   

139,708

 

Other, Net

(465)

   

(424)

   

(1,185)

   

1,215

 

Changes in Components of Working Capital and Other Assets and
     Liabilities

             

Accounts Receivable

(260,829)

   

63,891

   

930,628

   

(5,855)

 

Inventories

7,439

   

66,857

   

92,014

   

55,598

 

Accounts Payable

(37,755)

   

7,400

   

(1,222,473)

   

134,253

 

Accrued Taxes Payable

73,482

   

34,767

   

12,395

   

88,047

 

Other Assets

161,879

   

(92,814)

   

414,857

   

394,573

 

Other Liabilities

51,664

   

39,791

   

(12,739)

   

(18,315)

 

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

(6,091)

   

(16,643)

   

276,063

   

(38,677)

 

Net Cash Provided by Operating Activities

1,213,553

   

2,061,664

   

3,886,545

   

6,355,976

 

Investing Cash Flows

             

Additions to Oil and Gas Properties

(468,487)

   

(1,420,385)

   

(2,458,520)

   

(4,866,882)

 

Additions to Other Property, Plant and Equipment

(17,652)

   

(70,469)

   

(165,018)

   

(187,350)

 

Proceeds from Sales of Assets

145,575

   

17,767

   

188,943

   

35,409

 

Changes in Components of Working Capital Associated with
     Investing Activities

6,091

   

16,621

   

(276,063)

   

38,677

 

Net Cash Used in Investing Activities

(334,473)

   

(1,456,466)

   

(2,710,658)

   

(4,980,146)

 

Financing Cash Flows

             

Long-Term Debt Borrowings

   

   

1,483,852

   

 

Long-Term Debt Repayments

   

   

(1,000,000)

   

(900,000)

 

Dividends Paid

(217,142)

   

(166,170)

   

(601,242)

   

(420,851)

 

Treasury Stock Purchased

(9,764)

   

(13,835)

   

(14,821)

   

(22,238)

 

Proceeds from Stock Options Exercised and Employee Stock
     Purchase Plan

   

863

   

8,614

   

9,558

 

Debt Issuance Costs

   

(114)

   

(2,635)

   

(5,016)

 

Repayment of Finance Lease Liabilities

(4,864)

   

(3,235)

   

(13,309)

   

(9,638)

 

Changes in Components of Working Capital Associated with
     Financing Activities

   

22

   

   

 

Net Cash Used in Financing Activities

(231,770)

   

(182,469)

   

(139,541)

   

(1,348,185)

 

Effect of Exchange Rate Changes on Cash

1,745

   

(109)

   

1,238

   

(174)

 

Increase in Cash and Cash Equivalents

649,055

   

422,620

   

1,037,584

   

27,471

 

Cash and Cash Equivalents at Beginning of Period

2,416,501

   

1,160,485

   

2,027,972

   

1,555,634

 

Cash and Cash Equivalents at End of Period

3,065,556

   

1,583,105

   

3,065,556

   

1,583,105

 

 

Non-GAAP Financial Measures

 
 

To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP.   These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Discretionary Cash Flow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics.

 

A reconciliation of each of these measures to their most directly comparable GAAP financial measure is included in the tables below and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com.

 

EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance.

 

EOG believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods.

 

The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Total Debt, Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP.

 

In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. 

 

Adjusted Net Income (Loss)

 

In thousands of USD, except per share data (Unaudited)

 

3Q 2020

 

Before

Tax

 

Income Tax
Impact

 

After

Tax

 

Diluted
Earnings
per Share

               

Reported Net Loss (GAAP)

(52,555)

   

10,088

   

(42,467)

   

(0.07)

 

Adjustments:

             

Losses on Mark-to-Market Commodity Derivative Contracts

3,978

   

(873)

   

3,105

   

(0.01)

 

Net Cash Received from Settlements of Commodity Derivative Contracts

275,133

   

(60,386)

   

214,747

   

0.37

 

Add: Losses on Asset Dispositions, Net

70,976

   

(15,600)

   

55,376

   

0.10

 

Add: Certain Impairments

26,531

   

(5,636)

   

20,895

   

0.04

 

Adjustments to Net Income (Loss)

376,618

   

(82,495)

   

294,123

   

0.50

 
               

Adjusted Net Income (Non-GAAP)

324,063

   

(72,407)

   

251,656

   

0.43

 
               

Average Number of Common Shares (GAAP)

             

Basic

           

579,055

 

Diluted

           

579,055

 
               

Average Number of Common Shares (Non-GAAP)

             

Basic

           

579,055

 

Diluted

           

580,609

 
   
 

3Q 2019

 

Before

Tax

 

Income Tax
Impact

 

After

Tax

 

Diluted Earnings
per Share

               

Reported Net Income (GAAP)

797,457

   

(182,335)

   

615,122

   

1.06

 

Adjustments:

             

Gains on Mark-to-Market Commodity Derivative Contracts

(85,902)

   

18,854

   

(67,048)

   

(0.12)

 

Net Cash Received from Settlements of Commodity Derivative Contracts

108,418

   

(23,796)

   

84,622

   

0.15

 

Add: Losses on Asset Dispositions, Net

523

   

(89)

   

434

   

 

Add: Certain Impairments

27,215

   

(5,973)

   

21,242

   

0.04

 

Adjustments to Net Income (Loss)

50,254

   

(11,004)

   

39,250

   

0.07

 
               

Adjusted Net Income (Non-GAAP)

847,711

   

(193,339)

   

654,372

   

1.13

 
               

Average Number of Common Shares (GAAP)

             

Basic

           

577,839

 

Diluted

           

581,271

 
               

Average Number of Common Shares (Non-GAAP)

           

577,839

 

Basic

           

581,271

 

Diluted

             

 

Adjusted Net Income (Loss)

 

In thousands of USD, except per share data (Unaudited)

 

YTD 2020

 

Before

Tax

 

Income Tax
Impact

 

After

Tax

 

Diluted Earnings
per Share

               

Reported Net Loss (GAAP)

(1,166,814)

   

224,776

   

(942,038)

   

(1.63)

 

Adjustments:

             

Gains on Mark-to-Market Commodity Derivative Contracts

(1,075,433)

   

236,036

   

(839,397)

   

(1.45)

 

Net Cash Received from Settlements of Commodity Derivative Contracts

998,894

   

(219,237)

   

779,657

   

1.35

 

Add: Losses on Asset Dispositions, Net

41,283

   

(9,057)

   

32,226

   

0.06

 

Add: Certain Impairments

1,782,014

   

(373,960)

   

1,408,054

   

2.43

 

Adjustments to Net Income (Loss)

1,746,758

   

(366,218)

   

1,380,540

   

2.39

 
               

Adjusted Net Income (Non-GAAP)

579,944

   

(141,442)

   

438,502

   

0.76

 
               

Average Number of Common Shares (GAAP)

             

Basic

           

578,740

 

Diluted

           

578,740

 
               

Average Number of Common Shares (Non-GAAP)

             

Basic

           

578,740

 

Diluted

           

580,301

 
   
 

YTD 2019

 

Before

Tax

 

Income Tax
Impact

 

After

Tax

 

Diluted
Earnings
per Share

               

Reported Net Income (GAAP)

2,714,059

   

(615,670)

   

2,098,389

   

3.61

 

Adjustments:

             

Gains on Mark-to-Market Commodity Derivative Contracts

(242,622)

   

53,251

   

(189,371)

   

(0.34)

 

Net Cash Received from Settlements of Commodity Derivative Contracts

139,708

   

(30,663)

   

109,045

   

0.19

 

Add: Gains on Asset Dispositions, Net

(3,650)

   

910

   

(2,740)

   

 

Add: Certain Impairments

116,249

   

(25,514)

   

90,735

   

0.16

 

Adjustments to Net Income (Loss)

9,685

   

(2,016)

   

7,669

   

0.01

 
               

Adjusted Net Income (Non-GAAP)

2,723,744

   

(617,686)

   

2,106,058

   

3.62

 
               

Average Number of Common Shares (GAAP)

             

Basic

           

577,498

 

Diluted

           

581,190

 
               

Average Number of Common Shares (Non-GAAP)

             

Basic

           

577,498

 

Diluted

           

581,190

 

 

Discretionary Cash Flow and Free Cash Flow

 

In thousands of USD (Unaudited)

 

3Q 2020

 

3Q 2019

 

YTD 2020

 

YTD 2019

               

Net Cash Provided by Operating Activities (GAAP)

1,213,553

   

2,061,664

   

3,886,545

   

6,355,976

 
               

Adjustments:

             

Exploration Costs (excluding Stock-Based Compensation Expenses)

37,380

   

29,374

   

90,346

   

85,250

 

Other Non-Current Income Taxes - Net Receivable

   

33,855

   

112,704

   

179,537

 

Changes in Components of Working Capital and Other Assets and
     Liabilities

             

Accounts Receivable

260,829

   

(63,891)

   

(930,628)

   

5,855

 

Inventories

(7,439)

   

(66,857)

   

(92,014)

   

(55,598)

 

Accounts Payable

37,755

   

(7,400)

   

1,222,473

   

(134,253)

 

Accrued Taxes Payable

(73,482)

   

(34,767)

   

(12,395)

   

(88,047)

 

Other Assets

(161,879)

   

92,814

   

(414,857)

   

(394,573)

 

Other Liabilities

(51,664)

   

(39,791)

   

12,739

   

18,315

 

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

6,091

   

16,643

   

(276,063)

   

38,677

 

Discretionary Cash Flow (Non-GAAP)

1,261,144

   

2,021,644

   

3,598,850

   

6,011,139

 
               

Discretionary Cash Flow (Non-GAAP) - Percentage Decrease

-38

%

     

-40

%

   
               

Discretionary Cash Flow (Non-GAAP)

1,261,144

   

2,021,644

   

3,598,850

   

6,011,139

 

Less:

             

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)

(499,305)

   

(1,518,019)

   

(2,661,641)

   

(4,846,221)

 

Free Cash Flow (Non-GAAP) (b)

761,839

   

503,625

   

937,209

   

1,164,918

 
               

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month and nine-month periods ended September 30, 2020 and 2019:

               

Total Expenditures (GAAP)

645,534

   

1,629,343

   

3,005,723

   

5,394,389

 

Less:

             

Asset Retirement Costs

(42,650)

   

(90,970)

   

(68,213)

   

(151,551)

 

Non-Cash Expenditures of Other Property, Plant and Equipment

   

   

(60)

   

(586)

 

Non-Cash Acquisition Costs of Unproved Properties

(80,757)

   

(10,666)

   

(128,488)

   

(64,387)

 

Non-Cash Finance Leases

   

   

(73,277)

   

 

Acquisition Costs of Proved Properties

(22,822)

   

(9,688)

   

(74,044)

   

(331,644)

 

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)

499,305

   

1,518,019

   

2,661,641

   

4,846,221

 
               

(b) To better align the  presentation of  free cash  flow for comparative purposes  within the industry, free cash flow  excludes dividends paid (GAAP) as a reconciling item for the three-month and nine-month periods ending September 30, 2020.  The comparative prior periods shown have been revised to conform to this presentation.

               

Maintenance Capital Expenditures

             

The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to anticipated 4Q 2020 U.S. oil production.

 

Discretionary Cash Flow and Free Cash Flow

 

In thousands of USD (Unaudited)

           
 

FY 2019

 

FY 2018

 

FY 2017

           

Net Cash Provided by Operating Activities (GAAP)

8,163,180

   

7,768,608

   

4,265,336

 
           

Adjustments:

         

Exploration Costs (excluding Stock-Based Compensation Expenses)

113,733

   

123,986

   

122,688

 

Other Non-Current Income Taxes - Net (Payable) Receivable

238,711

   

148,993

   

(513,404)

 

Changes in Components of Working Capital and Other Assets and Liabilities

         

Accounts Receivable

91,792

   

368,180

   

392,131

 

Inventories

(90,284)

   

395,408

   

174,548

 

Accounts Payable

(168,539)

   

(439,347)

   

(324,192)

 

Accrued Taxes Payable

(40,122)

   

92,461

   

63,937

 

Other Assets

(358,001)

   

125,435

   

658,609

 

Other Liabilities

56,619

   

(10,949)

   

89,871

 

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

115,061

   

(301,083)

   

(89,992)

 

Discretionary Cash Flow (Non-GAAP)

8,122,150

   

8,271,692

   

4,839,532

 
           

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

-2

%

 

71

%

 

76

%

           

Discretionary Cash Flow (Non-GAAP)

8,122,150

   

8,271,692

   

4,839,532

 

Less:

         

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)

(6,234,454)

   

(6,172,950)

   

(4,228,859)

 

Free Cash Flow (Non-GAAP) (b)

1,887,696

   

2,098,742

   

610,673

 
           

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017:

           

Total Expenditures (GAAP)

6,900,450

   

6,706,359

   

4,612,746

 

Less:

         

Asset Retirement Costs

(186,088)

   

(69,699)

   

(55,592)

 

Non-Cash Expenditures of Other Property, Plant and Equipment

(2,266)

   

(49,484)

   

 

Non-Cash Acquisition Costs of Unproved Properties

(97,704)

   

(290,542)

   

(255,711)

 

Acquisition Costs of Proved Properties

(379,938)

   

(123,684)

   

(72,584)

 

Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)

6,234,454

   

6,172,950

   

4,228,859

 
           

(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019.  The comparative prior periods shown have been revised to conform to this presentation.

 

Discretionary Cash Flow and Free Cash Flow

 

In thousands of USD (Unaudited)

                   
 

FY 2016

 

FY 2015

 

FY 2014

 

FY 2013

 

FY 2012

                   

Net Cash Provided by Operating Activities (GAAP)

2,359,063

   

3,595,165

   

8,649,155

   

7,329,414

   

5,236,777

 
                   

Adjustments:

                 

Exploration Costs (excluding Stock-Based
     Compensation Expenses)

104,199

   

124,011

   

157,453

   

134,531

   

159,182

 

Excess Tax Benefits from Stock-Based Compensation

29,357

   

26,058

   

99,459

   

55,831

   

67,035

 

Changes in Components of Working Capital and
     Other Assets and Liabilities

                 

Accounts Receivable

232,799

   

(641,412)

   

(84,982)

   

23,613

   

178,683

 

Inventories

(170,694)

   

(58,450)

   

161,958

   

(53,402)

   

156,762

 

Accounts Payable

74,048

   

1,409,197

   

(543,630)

   

(178,701)

   

17,150

 

Accrued Taxes Payable

(92,782)

   

(11,798)

   

(16,486)

   

(75,142)

   

(78,094)

 

Other Assets

40,636

   

(118,143)

   

14,448

   

109,567

   

118,520

 

Other Liabilities

16,225

   

66,257

   

(75,420)

   

20,382

   

(36,114)

 

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

156,102

   

(499,767)

   

103,414

   

51,361

   

(74,158)

 

Discretionary Cash Flow (Non-GAAP)

2,748,953

   

3,891,118

   

8,465,369

   

7,417,454

   

5,745,743

 
                   

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

-29

%

 

-54

%

 

14

%

 

29

%

   
                   

Discretionary Cash Flow (Non-GAAP)

2,748,953

   

3,891,118

   

8,465,369

   

7,417,454

   

5,745,743

 

Less:

                 

Total Cash Capital Expenditures Before Acquisitions
      (Non-GAAP) (a)

(2,706,397)

   

(4,682,326)

   

(8,292,090)

   

(7,101,791)

   

(7,539,994)

 

Free Cash Flow (Non-GAAP) (b)

42,556

   

(791,208)

   

173,279

   

315,663

   

(1,794,251)

 
                   

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2016, 2015, 2014, 2013 and 2012:

                   

Total Expenditures (GAAP)

6,554,053

   

5,216,413

   

8,631,906

   

7,361,457

   

7,753,828

 

Less:

                 

Asset Retirement Costs

19,865

   

(53,470)

   

(195,630)

   

(134,445)

   

(126,987)

 

Non-Cash Expenditures of Other Property, Plant
     and Equipment

(16,585)

   

   

   

   

(65,791)

 

Non-Cash Acquisition Costs of Unproved Properties

(3,101,913)

   

   

(5,085)

   

(5,007)

   

(20,317)

 

Acquisition Costs of Proved Properties

(749,023)

   

(480,617)

   

(139,101)

   

(120,214)

   

(739)

 

Total Cash Capital Expenditures Before Acquisitions
     (Non-GAAP)

2,706,397

   

4,682,326

   

8,292,090

   

7,101,791

   

7,539,994

 
                   

(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item.

 

Total Expenditures

 

In millions of USD (Unaudited)

                   
 

3Q 2020

 

3Q 2019

 

FY 2019

 

FY 2018

 

FY 2017

                   

Exploration and Development Drilling

378

   

1,173

   

4,951

   

4,935

   

3,132

 

Facilities

38

   

161

   

629

   

625

   

575

 

Leasehold Acquisitions

88

   

56

   

276

   

488

   

427

 

Property Acquisitions

23

   

10

   

380

   

124

   

73

 

Capitalized Interest

7

   

10

   

38

   

24

   

27

 

Subtotal

534

   

1,410

   

6,274

   

6,196

   

4,234

 

Exploration Costs

38

   

34

   

140

   

149

   

145

 

Dry Hole Costs

13

   

24

   

28

   

5

   

5

 

Exploration and Development Expenditures

585

   

1,468

   

6,442

   

6,350

   

4,384

 

Asset Retirement Costs

44

   

91

   

186

   

70

   

56

 

Total Exploration and Development Expenditures

629

   

1,559

   

6,628

   

6,420

   

4,440

 

Other Property, Plant and Equipment

17

   

70

   

272

   

286

   

173

 

Total Expenditures

646

   

1,629

   

6,900

   

6,706

   

4,613

 

 

EBITDAX and Adjusted EBITDAX

 

In thousands of USD (Unaudited)

 

3Q 2020

 

3Q 2019

 

YTD 2020

 

YTD 2019

               

Net Income (Loss) (GAAP)

(42,467)

   

615,122

   

(942,038)

   

2,098,389

 
               

Adjustments:

             

Interest Expense, Net

53,242

   

39,620

   

152,145

   

144,434

 

Income Tax Provision (Benefit)

(10,088)

   

182,335

   

(224,776)

   

615,670

 

Depreciation, Depletion and Amortization

823,050

   

953,597

   

2,529,789

   

2,790,496

 

Exploration Costs

38,413

   

34,540

   

105,373

   

103,386

 

Dry Hole Costs

12,604

   

24,138

   

13,063

   

28,001

 

Impairments

78,990

   

105,275

   

1,957,340

   

289,761

 

EBITDAX (Non-GAAP)

953,744

   

1,954,627

   

3,590,896

   

6,070,137

 

(Gains) Losses on MTM Commodity Derivative Contracts

3,978

   

(85,902)

   

(1,075,433)

   

(242,622)

 

Net Cash Received from Settlements of Commodity Derivative Contracts

275,133

   

108,418

   

998,894

   

139,708

 

(Gains) Losses on Asset Dispositions, Net

70,976

   

523

   

41,283

   

(3,650)

 
               

Adjusted EBITDAX (Non-GAAP)

1,303,831

   

1,977,666

   

3,555,640

   

5,963,573

 
               

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

-34

%

     

-40

%

   
               

Definitions

             

EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments

 

Net Debt-to-Total Capitalization Ratio

 

In millions of USD, except ratio data (Unaudited)

 

September 30,

2020

 

June 30,

2020

 

March 31,

2020

           

Total Stockholders' Equity - (a)

20,148

   

20,388

   

21,471

 
           

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

5,721

   

5,724

   

5,222

 

Less: Cash

(3,066)

   

(2,417)

   

(2,907)

 

Net Debt (Non-GAAP) - (c)

2,655

   

3,307

   

2,315

 
           

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

25,869

   

26,112

   

26,693

 
           

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

22,803

   

23,695

   

23,786

 
           

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

22

%

 

22

%

 

20

%

           

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

12

%

 

14

%

 

10

%

 

Net Debt-to-Total Capitalization Ratio

 

In millions of USD, except ratio data (Unaudited)

 

December 31,
2019

 

September 30,
2019

 

June 30,

2019

 

March 31,

2019

               

Total Stockholders' Equity - (a)

21,641

   

21,124

   

20,630

   

19,904

 
               

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

5,175

   

5,177

   

5,179

   

6,081

 

Less: Cash

(2,028)

   

(1,583)

   

(1,160)

   

(1,136)

 

Net Debt (Non-GAAP) - (c)

3,147

   

3,594

   

4,019

   

4,945

 
               

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

26,816

   

26,301

   

25,809

   

25,985

 
               

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

24,788

   

24,718

   

24,649

   

24,849

 
               

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

19

%

 

20

%

 

20

%

 

23

%

               

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

13

%

 

15

%

 

16

%

 

20

%

 

Net Debt-to-Total Capitalization Ratio

 

In millions of USD, except ratio data (Unaudited)

 

December 31,

2018

 

September 30,

2018

 

June 30,

2018

 

March 31,

2018

             

Total Stockholders' Equity - (a)

19,364

   

18,538

   

17,452

   

16,841

 
               

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

6,083

   

6,435

   

6,435

   

6,435

 

Less: Cash

(1,556)

   

(1,274)

   

(1,008)

   

(816)

 

Net Debt (Non-GAAP) - (c)

4,527

   

5,161

   

5,427

   

5,619

 
               

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

25,447

   

24,973

   

23,887

   

23,276

 
               

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

23,891

   

23,699

   

22,879

   

22,460

 
               

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

24

%

 

26

%

 

27

%

 

28

%

               

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

19

%

 

22

%

 

24

%

 

25

%

 

Net Debt-to-Total Capitalization Ratio

 

In millions of USD, except ratio data (Unaudited)

           
 

December 31,

2017

 

September 30,

2017

 

June 30,

2017

 

March 31,

2017

             

Total Stockholders' Equity - (a)

16,283

   

13,922

   

13,902

   

13,928

 
               

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

6,387

   

6,387

   

6,987

   

6,987

 

Less: Cash

(834)

   

(846)

   

(1,649)

   

(1,547)

 

Net Debt (Non-GAAP) - (c)

5,553

   

5,541

   

5,338

   

5,440

 
               

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

22,670

   

20,309

   

20,889

   

20,915

 
               

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

21,836

   

19,463

   

19,240

   

19,368

 
               

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

28

%

 

31

%

 

33

%

 

33

%

               

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

25

%

 

28

%

 

28

%

 

28

%

 

Net Debt-to-Total Capitalization Ratio

 

In millions of USD, except ratio data (Unaudited)

 

December 31,
2016

 

September 30,
2016

 

June 30,

2016

 

March 31,

2016

 

December 31,

2015

                 

Total Stockholders' Equity - (a)

13,982

   

11,798

   

12,057

   

12,405

   

12,943

 
                   

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

6,986

   

6,986

   

6,986

   

6,986

   

6,660

 

Less: Cash

(1,600)

   

(1,049)

   

(780)

   

(668)

   

(719)

 

Net Debt (Non-GAAP) - (c)

5,386

   

5,937

   

6,206

   

6,318

   

5,941

 
                   

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

20,968

   

18,784

   

19,043

   

19,391

   

19,603

 
                   

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

19,368

   

17,735

   

18,263

   

18,723

   

18,884

 
                   

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

33

%

 

37

%

 

37

%

 

36

%

 

34

%

                   

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

28

%

 

33

%

 

34

%

 

34

%

 

31

%

 

Reserve Replacement Cost Data

 

In millions of USD, except reserves and ratio data (Unaudited)

                       
 

2019

 

2018

 

2017

 

2016

 

2015

 

2014

                       

Total Costs Incurred in Exploration and Development
     Activities (GAAP)

6,628.2

   

6,419.7

   

4,439.4

   

6,445.2

   

4,928.3

   

7,904.8

 

Less:  Asset Retirement Costs

(186.1)

   

(69.7)

   

(55.6)

   

19.9

   

(53.5)

   

(195.6)

 

Non-Cash Acquisition Costs of Unproved
     Properties

(97.7)

   

(290.5)

   

(255.7)

   

(3,101.8)

   

   

 

Acquisition Costs of Proved Properties

(379.9)

   

(123.7)

   

(72.6)

   

(749.0)

   

(480.6)

   

(139.1)

 

Total Exploration and Development Expenditures for
     Drilling Only (Non-GAAP) - (a)

5,964.5

   

5,935.8

   

4,055.5

   

2,614.3

   

4,394.2

   

7,570.1

 
                       

Total Costs Incurred in Exploration and Development
     Activities (GAAP)

6,628.2

   

6,419.7

   

4,439.4

   

6,445.2

   

4,928.3

   

7,904.8

 

Less:  Asset Retirement Costs

(186.1)

   

(69.7)

   

(55.6)

   

19.9

   

(53.5)

   

(195.6)

 

Non-Cash Acquisition Costs of Unproved
     Properties

(97.7)

   

(290.5)

   

(255.7)

   

(3,101.8)

   

   

 

Non-Cash Acquisition Costs of Proved Properties

(52.3)

   

(70.9)

   

(26.2)

   

(732.3)

   

   

 

Total Exploration and Development Expenditures
     (Non-GAAP) - (b)

6,292.1

   

5,988.6

   

4,101.9

   

2,631.0

   

4,874.8

   

7,709.2

 
                       

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

                     

Revisions Due to Price - (c)

(59.7)

   

34.8

   

154.0

   

(100.7)

   

(573.8)

   

52.2

 

Revisions Other Than Price

(0.3)

   

(39.5)

   

48.0

   

252.9

   

107.2

   

48.4

 

Purchases in Place

16.8

   

11.6

   

2.3

   

42.3

   

56.2

   

14.4

 

Extensions, Discoveries and Other Additions - (d)

750.0

   

669.7

   

420.8

   

209.0

   

245.9

   

519.2

 

Total Proved Reserve Additions - (e)

706.8

   

676.6

   

625.1

   

403.5

   

(164.5)

   

634.2

 

Sales in Place

(4.6)

   

(10.8)

   

(20.7)

   

(167.6)

   

(3.5)

   

(36.3)

 

Net Proved Reserve Additions From All Sources

702.2

   

665.8

   

604.4

   

235.9

   

(168.0)

   

597.9

 
                       

Production

300.9

   

265.0

   

224.4

   

207.1

   

211.2

   

219.1

 
                       

Reserve Replacement Costs ($ / Boe)

                     

Total Drilling, Before Revisions - (a / d)

7.95

   

8.86

   

9.64

   

12.51

   

17.87

   

14.58

 

All-in Total, Net of Revisions - (b / e)

8.90

   

8.85

   

6.56

   

6.52

   

(29.63)

   

12.16

 

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

8.21

   

9.33

   

8.71

   

5.22

   

11.91

   

13.25

 

 

Definitions

 

$/Boe

U.S. Dollars per barrel of oil equivalent

MMBoe

Million barrels of oil equivalent

 

Financial Commodity Derivative Contracts

   

EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.

 
   

ICE Brent Differential Basis Swap Contracts

 

Prices received by EOG for its crude oil production generally vary from NYMEX WTI 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 ICE Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through October 30, 2020. 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.

 
           

2020

 

Volume
(Bbld)

 

Weighted
Average Price
Differential

($/Bbl)

 
 
 

May 2020 (CLOSED)

 

10,000

   

4.92

   
               

Houston Differential Basis Swap Contracts

 

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential).  Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through October 30, 2020.  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.

 
           

2020

 

Volume
(Bbld)

 

Weighted

Average Price Differential

($/Bbl)

 
 
 

May 2020 (CLOSED)

 

10,000

   

1.55

   
               

Roll Differential Swap Contracts

 

EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential).  Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through October 30, 2020.  The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

 
           

2020

 

Volume
(Bbld)

 

Weighted
Average Price Differential

($/Bbl)

 
 
 

February 1, 2020 through June 30, 2020 (CLOSED)

 

10,000

   

0.70

   

July 1, 2020 through September 30, 2020 (CLOSED)

 

88,000

   

(1.16)

   

October 1, 2020 through November 30, 2020 (CLOSED)

 

66,000

   

(1.16)

   

December 2020

 

66,000

   

(1.16)

   
               

In May 2020, EOG entered into crude oil Roll Differential swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $2.6 million through October 30, 2020, for the settlement of certain of these contracts and expects to pay $0.6 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

   

Crude Oil NYMEX WTI Price Swap Contracts

 

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

 
           

2020

 

Volume
(Bbld)

 

Weighted
Average Price
($/Bbl)

 
 
 

January 1, 2020 through March 31, 2020 (CLOSED)

 

200,000

   

59.33

   

April 1, 2020 through May 31, 2020 (CLOSED)

 

265,000

   

51.36

   
           

In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020.  EOG received net cash of $359.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $4.1 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

 
   

Crude Oil ICE Brent Price Swap Contracts

 

Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

 
           

2020

 

Volume
(Bbld)

 

Weighted
Average Price
($/Bbl)

 
 
 

April 2020 (CLOSED)

 

75,000

   

25.66

   

May 2020 (CLOSED)

 

35,000

   

26.53

   
   

Mont Belvieu Propane Price Swap Contracts

 

Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

 
           

2020

 

Volume
(Bbld)

 

Weighted
Average Price
($/Bbl)

 
 
 

January 1, 2020 through February 29, 2020 (CLOSED)

 

4,000

   

21.34

   

March 1, 2020 through April 30, 2020 (CLOSED)

 

25,000

   

17.92

   
           

In April and May 2020, EOG entered into Mont Belvieu Propane Price Swap Contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl.  These contracts offset the remaining Mont Belvieu Propane Price Swap Contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl.  EOG received net cash of $5.7 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $3.5 million during the remainder of 2020 for the settlement of the remaining contracts.  The offsetting contracts were excluded from the above table.

 
   

Natural Gas Price Swap Contracts

 

Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

 
           

2021

 

Volume
(MMBtud)

 

Weighted
Average Price

 ($/MMBtu)

 
 
 

January 1, 2021 through December 31, 2021

 

500,000

   

2.99

   
               

 

 

Natural Gas Collar Contracts

 

EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts.  The collars require that EOG pay the difference between the ceiling price and the 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 ceiling price.  The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price.  In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020.  EOG received net cash of $7.8 million for the settlement of these contracts.  Presented below is a comprehensive summary of EOG's natural gas collar contracts through October 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

 
               

2020

 

Volume
(MMBtud)

 

Weighted
Average

Ceiling Price

($/MMBtu)

 

Weighted
Average
Floor Price
($/MMBtu)

 
 

April 1, 2020 through July 31, 2020 (CLOSED)

 

250,000

   

2.50

   

2.00

   
               

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.  These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu.  EOG received net cash of $1.1 million through October 30, 2020, for the settlement of these contracts.  The offsetting contracts were excluded from the above table.

 
                     

 

 

 

Rockies Differential Basis Swap Contracts

 

Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors.  EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential).  Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through October 30, 2020.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

 
           

2020

 

Volume
(MMBtud)

 

Weighted
Average Price
Differential
($/MMBtu)

 
 
 

January 1, 2020 through October 31, 2020 (CLOSED)

 

30,000

   

0.55

   

November 1, 2020 through December 31, 2020

 

30,000

   

0.55

   
   

HSC Differential Basis Swap Contracts

 

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential).  In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020.  EOG paid net cash of $0.4 million for the settlement of these contracts.  Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through October 30, 2020.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

 
           

2020

 

Volume
(MMBtud)

 

Weighted
Average Price
Differential
($/MMBtu)

 
 
 

January 1, 2020 through December 31, 2020 (CLOSED)

 

60,000

   

0.05

   
               

Waha Differential Basis Swap Contracts

 

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential).  Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through October 30, 2020.  The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

 
           

2020

 

Volume
(MMBtud)

 

Weighted
Average Price
Differential 
($/MMBtu)

 
 
 

January 1, 2020 through April 30, 2020 (CLOSED)

 

50,000

   

1.40

   
           

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu.  These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu.  EOG paid net cash of $8.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to pay net cash of $3.0 million during the remainder of 2020 for the settlement of the remaining contracts.  The offsetting contracts were excluded from the above table.

 
               

 

Definitions

 

Bbld

 

Barrels per day

 

$/Bbl

 

Dollars per barrel

 

ICE

 

Intercontinental Exchange

 

MMBtud

 

Million British thermal units per day

 

$/MMBtu

 

Dollars per million British thermal units

 

NYMEX

 

U.S. New York Mercantile Exchange

 

WTI

 

West Texas Intermediate

 

 

Direct After-Tax Rate of Return

 

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

 

 

ROCE & ROE

 

In millions of USD, except ratio data (Unaudited)

 

2019

 

2018

 

2017

           

Net Interest Expense (GAAP)

185

   

245

     

Tax Benefit Imputed (based on 21%)

(39)

   

(51)

     

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

146

   

194

     
           

Net Income (GAAP) - (b)

2,735

   

3,419

     

Adjustments to Net Income, Net of Tax (See Below Detail) (1)

158

   

(201)

     

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

2,893

   

3,218

     
           

Total Stockholders' Equity - (d)

21,641

   

19,364

   

16,283

 
           

Average Total Stockholders' Equity * - (e)

20,503

   

17,824

     
           

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

5,175

   

6,083

   

6,387

 

Less:  Cash

(2,028)

   

(1,556)

   

(834)

 

Net Debt (Non-GAAP) - (g)

3,147

   

4,527

   

5,553

 
           

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

26,816

   

25,447

   

22,670

 
           

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

24,788

   

23,891

   

21,836

 
           

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

24,340

   

22,864

     
           

Return on Capital Employed (ROCE)

         

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

11.8

%

 

15.8

%

   

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

12.5

%

 

14.9

%

   
           

Return on Equity (ROE)

         

GAAP Net Income - (b) / (e)

13.3

%

 

19.2

%

   

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

14.1

%

 

18.1

%

   
           

* Average for the current and immediately preceding year

         
           

(1) Detail of adjustments to Net Income (GAAP):

         
 

Before
Tax

 

Income Tax

Impact

 

After
Tax

Year Ended December 31, 2019

         

Adjustments:

         

Add:  Mark-to-Market Commodity Derivative Contracts Impact

51

   

(11)

   

40

 

Add:  Impairments of Certain Assets

275

   

(60)

   

215

 

Less:  Net Gains on Asset Dispositions

(124)

   

27

   

(97)

 

Total

202

   

(44)

   

158

 
           

Year Ended December 31, 2018

         

Adjustments:

         

Add:  Mark-to-Market Commodity Derivative Contracts Impact

(93)

   

20

   

(73)

 

Add:  Impairments of Certain Assets

153

   

(34)

   

119

 

Less:  Net Gains on Asset Dispositions

(175)

   

38

   

(137)

 

Less:  Tax Reform Impact

   

(110)

   

(110)

 

Total

(115)

   

(86)

   

(201)

 

 

ROCE & ROE

 

In millions of USD, except ratio data (Unaudited)

                   
 

2017

 

2016

 

2015

 

2014

 

2013

                   

Net Interest Expense (GAAP)

274

   

282

   

237

   

201

   

235

 

Tax Benefit Imputed (based on 35%)

(96)

   

(99)

   

(83)

   

(70)

   

(82)

 

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

178

   

183

   

154

   

131

   

153

 
                   

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

2,583

   

(1,097)

   

(4,525)

   

2,915

   

2,197

 
                   

Total Stockholders' Equity - (d)

16,283

   

13,982

   

12,943

   

17,713

   

15,418

 
                   

Average Total Stockholders' Equity* - (e)

15,133

   

13,463

   

15,328

   

16,566

   

14,352

 
                   

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

6,387

   

6,986

   

6,655

   

5,906

   

5,909

 

Less:  Cash

(834)

   

(1,600)

   

(719)

   

(2,087)

   

(1,318)

 

Net Debt (Non-GAAP) - (g)

5,553

   

5,386

   

5,936

   

3,819

   

4,591

 
                   

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

22,670

   

20,968

   

19,598

   

23,619

   

21,327

 
                   

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

21,836

   

19,368

   

18,879

   

21,532

   

20,009

 
                   

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

20,602

   

19,124

   

20,206

   

20,771

   

19,365

 
                   

Return on Capital Employed (ROCE)

                 

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

13.4

%

 

-4.8

%

 

-21.6

%

 

14.7

%

 

12.1

%

                   

Return on Equity (ROE)

                 

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

17.1

%

 

-8.1

%

 

-29.5

%

 

17.6

%

 

15.3

%

                   

* Average for the current and immediately preceding year

                 

 

ROCE & ROE

 

In millions of USD, except ratio data (Unaudited)

 
 

2012

 

2011

 

2010

 

2009

 

2008

                   

Net Interest Expense (GAAP)

214

   

210

   

130

   

101

   

52

 

Tax Benefit Imputed (based on 35%)

(75)

   

(74)

   

(46)

   

(35)

   

(18)

 

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

139

   

136

   

84

   

66

   

34

 
                   

Net Income (GAAP) - (b)

570

   

1,091

   

161

   

547

   

2,437

 
                   

Total Stockholders' Equity - (d)

13,285

   

12,641

   

10,232

   

9,998

   

9,015

 
                   

Average Total Stockholders' Equity* - (e)

12,963

   

11,437

   

10,115

   

9,507

   

8,003

 
                   

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

6,312

   

5,009

   

5,223

   

2,797

   

1,897

 

Less:  Cash

(876)

   

(616)

   

(789)

   

(686)

   

(331)

 

Net Debt (Non-GAAP) - (g)

5,436

   

4,393

   

4,434

   

2,111

   

1,566

 
                   

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

19,597

   

17,650

   

15,455

   

12,795

   

10,912

 
                   

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

18,721

   

17,034

   

14,666

   

12,109

   

10,581

 
                   

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

17,878

   

15,850

   

13,388

   

11,345

   

9,351

 
                   

Return on Capital Employed (ROCE)

                 

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

4.0

%

 

7.7

%

 

1.8

%

 

5.4

%

 

26.4

%

                   

Return on Equity (ROE)

                 

GAAP Net Income - (b) / (e)

4.4

%

 

9.5

%

 

1.6

%

 

5.8

%

 

30.5

%

                   

* Average for the current and immediately preceding year

                 

 

ROCE & ROE

 

In millions of USD, except ratio data (Unaudited)

                   
 

2007

 

2006

 

2005

 

2004

 

2003

                   

Net Interest Expense (GAAP)

47

   

43

   

63

   

63

   

59

 

Tax Benefit Imputed (based on 35%)

(16)

   

(15)

   

(22)

   

(22)

   

(21)

 

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

31

   

28

   

41

   

41

   

38

 
                   

Net Income (GAAP) - (b)

1,090

   

1,300

   

1,260

   

625

   

430

 
                   

Total Stockholders' Equity - (d)

6,990

   

5,600

   

4,316

   

2,945

   

2,223

 
                   

Average Total Stockholders' Equity* - (e)

6,295

   

4,958

   

3,631

   

2,584

   

1,948

 
                   

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

1,185

   

733

   

985

   

1,078

   

1,109

 

Less:  Cash

(54)

   

(218)

   

(644)

   

(21)

   

(4)

 

Net Debt (Non-GAAP) - (g)

1,131

   

515

   

341

   

1,057

   

1,105

 
                   

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

8,175

   

6,333

   

5,301

   

4,023

   

3,332

 
                   

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

8,121

   

6,115

   

4,657

   

4,002

   

3,328

 
                   

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

7,118

   

5,386

   

4,330

   

3,665

   

3,068

 
                   

Return on Capital Employed (ROCE)

                 

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

15.7

%

 

24.7

%

 

30.0

%

 

18.2

%

 

15.3

%

                   

Return on Equity (ROE)

                 

GAAP Net Income - (b) / (e)

17.3

%

 

26.2

%

 

34.7

%

 

24.2

%

 

22.1

%

                   

* Average for the current and immediately preceding year

                 

 

ROCE & ROE

 

In millions of USD, except ratio data (Unaudited)

 
 

2002

 

2001

 

2000

 

1999

 

1998

                   

Net Interest Expense (GAAP)

60

   

45

   

61

   

62

     

Tax Benefit Imputed (based on 35%)

(21)

   

(16)

   

(21)

   

(22)

     

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

39

   

29

   

40

   

40

     
                   

Net Income (GAAP) - (b)

87

   

399

   

397

   

569

     
                   

Total Stockholders' Equity - (d)

1,672

   

1,643

   

1,381

   

1,130

   

1,280

 
                   

Average Total Stockholders' Equity* - (e)

1,658

   

1,512

   

1,256

   

1,205

     
                   

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

1,145

   

856

   

859

   

990

   

1,143

 

Less:  Cash

(10)

   

(3)

   

(20)

   

(25)

   

(6)

 

Net Debt (Non-GAAP) - (g)

1,135

   

853

   

839

   

965

   

1,137

 
                   

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

2,817

   

2,499

   

2,240

   

2,120

   

2,423

 
                   

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

2,807

   

2,496

   

2,220

   

2,095

   

2,417

 
                   

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

2,652

   

2,358

   

2,158

   

2,256

     
                   

Return on Capital Employed (ROCE)

                 

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

4.8

%

 

18.2

%

 

20.2

%

 

27.0

%

   
                   

Return on Equity (ROE)

                 

GAAP Net Income - (b) / (e)

5.2

%

 

26.4

%

 

31.6

%

 

47.2

%

   
                   

* Average for the current and immediately preceding year

                 

 

Costs per Barrel of Oil Equivalent

 

In thousands of USD, except Boe and per Boe amounts (Unaudited)

               
 

1Q 2020

 

2Q 2020

 

3Q 2020

 

YTD 2020

               

Cost per Barrel of Oil Equivalent (Boe) Calculation

             

Volume - Thousand Barrels of Oil Equivalent - (a)

79,548

   

56,733

   

65,873

   

202,153

 
               

Crude Oil and Condensate

2,065,498

   

614,627

   

1,394,622

   

4,074,747

 

Natural Gas Liquids

160,535

   

93,909

   

184,771

   

439,215

 

Natural Gas

209,764

   

141,696

   

183,790

   

535,250

 

Total Wellhead Revenues - (b)

2,435,797

   

850,232

   

1,763,183

   

5,049,212

 
               

Operating Costs

             

Lease and Well

329,659

   

245,346

   

227,473

   

802,478

 

Transportation Costs

208,296

   

151,728

   

180,257

   

540,281

 

Gathering and Processing Costs

128,482

   

96,767

   

114,790

   

340,039

 

General and Administrative

114,273

   

131,855

   

124,460

   

370,588

 

Taxes Other Than Income

157,360

   

80,319

   

126,810

   

364,489

 

Interest Expense, Net

44,690

   

54,213

   

53,242

   

152,145

 

Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c)

982,760

   

760,228

   

827,032

   

2,570,020

 
               

Depreciation, Depletion and Amortization (DD&A)

1,000,060

   

706,679

   

823,050

   

2,529,789

 

Total Operating Cost (excluding Total Exploration Costs) - (d)

1,982,820

   

1,466,907

   

1,650,082

   

5,099,809

 
               

Exploration Costs

39,677

   

27,283

   

38,413

   

105,373

 

Dry Hole Costs

372

   

87

   

12,604

   

13,063

 

Impairments

1,572,935

   

305,415

   

78,990

   

1,957,340

 

Total Exploration Costs

1,612,984

   

332,785

   

130,007

   

2,075,776

 

Less:  Certain Impairments (Non-GAAP)

(1,516,316)

   

(239,167)

   

(26,531)

   

(1,782,014)

 

Total Exploration Costs (Non-GAAP)

96,668

   

93,618

   

103,476

   

293,762

 
               

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)

2,079,488

   

1,560,525

   

1,753,558

   

5,393,571

 
               

Composite Average Wellhead Revenue per Boe - (b) / (a)

30.62

   

14.99

   

26.77

   

24.98

 
               

Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs)

     -   (c) / (a)

12.36

   

13.40

   

12.56

   

12.70

 
               

Composite Average Margin per Boe (excluding DD&A and Total Exploration
     Costs) - [(b) / (a) - (c) / (a)]

18.26

   

1.59

   

14.21

   

12.28

 
               

Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a)

24.93

   

25.86

   

25.05

   

25.21

 
               

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) /
     (a) - (d) / (a)]

5.69

   

(10.87)

   

1.72

   

(0.23)

 
               

Total Operating Cost  per Boe (Non-GAAP) (including Total Exploration Costs) -
     (e) / (a)

26.15

   

27.51

   

26.62

   

26.66

 
               

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration 
     Costs) - [(b) / (a) - (e) / (a)]

4.47

   

(12.52)

   

0.15

   

(1.68)

 

 

 

 

Costs per Barrel of Oil Equivalent 

 

In thousands of USD, except Boe and per Boe amounts (Unaudited)

 

2019

 

2018

 

2017

Cost per Barrel of Oil Equivalent (Boe) Calculation

         

Volume - Thousand Barrels of Oil Equivalent - (a)

298,565

   

262,516

   

222,251

 
           

Crude Oil and Condensate

9,612,532

   

9,517,440

   

6,256,396

 

Natural Gas Liquids

784,818

   

1,127,510

   

729,561

 

Natural Gas

1,184,095

   

1,301,537

   

921,934

 

Total Wellhead Revenues - (b)

11,581,445

   

11,946,487

   

7,907,891

 
           

Operating Costs

         

Lease and Well

1,366,993

   

1,282,678

   

1,044,847

 

Transportation Costs

758,300

   

746,876

   

740,352

 

Gathering and Processing Costs

479,102

   

436,973

   

148,775

 

General and Administrative

489,397

   

426,969

   

434,467

 

Less:  Legal Settlement - Early Leasehold Termination

   

   

(10,202)

 

Less:  Joint Venture Transaction Costs

   

   

(3,056)

 

Less:  Joint Interest Billings Deemed Uncollectible

   

   

(4,528)

 

General and Administrative (Non-GAAP)

489,397

   

426,969

   

416,681

 

Taxes Other Than Income

800,164

   

772,481

   

544,662

 

Interest Expense, Net

185,129

   

245,052

   

274,372

 

Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c)

4,079,085

   

3,911,029

   

3,169,689

 
           

Depreciation, Depletion and Amortization (DD&A)

3,749,704

   

3,435,408

   

3,409,387

 

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d)

7,828,789

   

7,346,437

   

6,579,076

 
           

Exploration Costs

139,881

   

148,999

   

145,342

 

Dry Hole Costs

28,001

   

5,405

   

4,609

 

Impairments

517,896

   

347,021

   

479,240

 

Total Exploration Costs

685,778

   

501,425

   

629,191

 

Less:  Certain Impairments (Non-GAAP)

(274,974)

   

(152,671)

   

(261,452)

 

Total Exploration Costs (Non-GAAP)

410,804

   

348,754

   

367,739

 
           

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)

8,239,593

   

7,695,191

   

6,946,815

 

 

Cost per Barrel of Oil Equivalent

 

In thousands of USD, except Boe and per Boe amounts (Unaudited)

         
 

2019

 

2018

 

2017

           

Composite Average Wellhead Revenue per Boe - (b) / (a)

38.79

 

45.51

 

35.58

           

Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration

     Costs) -   (c) / (a)

13.66

 

14.90

 

14.25

           

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration
      Costs) - [(b) / (a) - (c) / (a)]

25.13

 

30.61

 

21.33

           

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) -
   (d) / (a)

26.22

 

27.99

 

29.59

           

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) -  
     [(b) / (a) - (d) / (a)]

12.57

 

17.52

 

5.99

           

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) -
   (e) / (a)

27.60

 

29.32

 

31.24

           

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - 

     [(b) / (a) - (e) / (a)]

11.19

 

16.19

 

4.34

 

Cost per Barrel of Oil Equivalent

 

In thousands of USD, except Boe and per Boe amounts (Unaudited)

   
 

2016

 

2015

 

2014

Cost per Barrel of Oil Equivalent (Boe) Calculation

         

Volume - Thousand Barrels of Oil Equivalent - (a)

204,929

   

208,862

   

217,073

           

Crude Oil and Condensate

4,317,341

   

4,934,562

   

9,742,480

Natural Gas Liquids

437,250

   

407,658

   

934,051

Natural Gas

742,152

   

1,061,038

   

1,916,386

Total Wellhead Revenues - (b)

5,496,743

   

6,403,258

   

12,592,917

           

Operating Costs

         

Lease and Well

927,452

   

1,182,282

   

1,416,413

Transportation Costs

764,106

   

849,319

   

972,176

Gathering and Processing Costs

122,901

   

146,156

   

145,800

           

General and Administrative

394,815

   

366,594

   

402,010

Less:  Voluntary Retirement Expense

(42,054)

   

   

Less:  Acquisition Costs

(5,100)

   

   

Less:  Legal Settlement - Early Leasehold Termination

   

(19,355)

   

General and Administrative (Non-GAAP)

347,661

   

347,239

   

402,010

           

Taxes Other Than Income

349,710

   

421,744

   

757,564

Interest Expense, Net

281,681

   

237,393

   

201,458

Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c)

2,793,511

   

3,184,133

   

3,895,421

           

Depreciation, Depletion and Amortization (DD&A)

3,553,417

   

3,313,644

   

3,997,041

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d)

6,346,928

   

6,497,777

   

7,892,462

           

Exploration Costs

124,953

   

149,494

   

184,388

Dry Hole Costs

10,657

   

14,746

   

48,490

Impairments

620,267

   

6,613,546

   

743,575

Total Exploration Costs

755,877

   

6,777,786

   

976,453

Less:  Certain Impairments (Non-GAAP)

(320,617)

   

(6,307,593)

   

(824,312)

Total Exploration Costs (Non-GAAP)

435,260

   

470,193

   

152,141

           

Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e)

6,782,188

   

6,967,970

   

8,044,603

           

 

Cost per Barrel of Oil Equivalent

 

In thousands of USD, except Boe and per Boe amounts (Unaudited)

   
 

2016

 

2015

 

2014

           

Composite Average Wellhead Revenue per Boe - (b) / (a)

26.82

 

30.66

 

58.01

           

Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration
     Costs) -   (c) / (a)

13.64

 

15.25

 

17.95

           

Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration
     Costs) - [(b) / (a) - (c) / (a)]

13.18

 

15.41

 

40.06

           

Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) -
   (d) / (a)

30.98

 

31.11

 

36.38

           

Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - 
     [(b) / (a) - (d) / (a)]

(4.16)

 

(0.45)

 

21.63

           

Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) -
   (e) / (a)

33.10

 

33.36

 

37.08

           

Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) -
     [(b) / (a) - (e) / (a)]

(6.28)

 

(2.70)

 

20.93

 

Quarter and Full Year Guidance

 

(Unaudited)

 

(a)  Fourth Quarter and Full Year 2020 Forecast

The forecast items for the fourth quarter and full year 2020 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)  Capital Expenditures

The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions.

 

(c)  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 for Fourth  Quarter and Full Year 2020

 

4Q 2020

   

FY 2020

Daily Sales Volumes

                     

Crude Oil and Condensate Volumes (MBbld)

                     

United States

 

435.0

 

-

 

445.0

     

406.3

 

-

 

408.8

 

Trinidad

 

1.6

 

-

 

2.0

     

0.8

 

-

 

0.9

 

Other International

 

0.0

 

-

 

0.2

     

0.1

 

-

 

0.1

 

Total

 

436.6

 

-

 

447.2

     

407.2

 

-

 

409.8

 

Natural Gas Liquids Volumes (MBbld)

                     

Total

 

140.0

 

-

 

150.0

     

137.2

 

-

 

139.7

 

Natural Gas Volumes (MMcfd)

                     

United States

 

1,040

 

-

 

1,100

     

1,032

 

-

 

1,047

 

Trinidad

 

170

 

-

 

190

     

174

 

-

 

179

 

Other International

 

20

 

-

 

30

     

30

 

-

 

33

 

Total

 

1,230

 

-

 

1,320

     

1,236

 

-

 

1,259

 

Crude Oil Equivalent Volumes (MBoed)

                     

United States

 

748.3

 

-

 

778.3

     

715.4

 

-

 

722.9

 

Trinidad

 

29.9

 

-

 

33.7

     

29.8

 

-

 

30.8

 

Other International

 

3.3

 

-

 

5.2

     

5.1

 

-

 

5.6

 

Total

 

781.5

 

-

 

817.2

     

750.3

 

-

 

759.3

 
                       

Capital Expenditures ($MM)

 

830

 

-

 

930

     

3,400

     

3,600

 

 

Quarter and Full Year Guidance

 

(Unaudited)

 

Estimated Ranges for Fourth Quarter and Full Year 2020

 

4Q 2020

   

FY 2020

Operating Costs

                     

Unit Costs ($/Boe)

                     

Lease and Well

 

3.80

 

-

 

4.30

     

3.92

 

-

 

4.05

 

Transportation Costs

 

2.55

 

-

 

2.95

     

2.64

 

-

 

2.74

 

Gathering and Processing

 

1.75

 

-

 

1.85

     

1.70

 

-

 

1.72

 

Depreciation, Depletion and Amortization

 

12.20

 

-

 

12.70

     

12.41

 

-

 

12.54

 

General and Administrative

 

1.80

 

-

 

1.90

     

1.82

 

-

 

1.85

 
                               

Expenses ($MM)

                     

Exploration and Dry Hole

 

45

 

-

 

55

     

163

 

-

 

173

 

Impairment

 

100

 

-

 

150

     

265

 

-

 

315

 

Capitalized Interest

 

5

 

-

 

10

     

29

 

-

 

34

 

Net Interest

 

51

 

-

 

56

     

203

 

-

 

208

 
                               

Taxes Other Than Income (% of Wellhead Revenue)

 

6.0

%

-

 

8.0

%

   

6.7

%

-

 

7.8

%

                               

Income Taxes

                     

Effective Rate

 

20

%

-

 

25

%

   

16

%

-

 

21

%

Current Tax (Benefit) / Expense ($MM)

 

10

 

-

 

50

     

(85)

 

-

 

(45)

 
                               

Pricing - (Refer to Benchmark Commodity Pricing in text)

                     

Crude Oil and Condensate ($/Bbl)

                     

Differentials

                     

United States - above (below) WTI

 

(1.85)

 

-

 

0.15

     

(1.07)

 

-

 

(0.52)

 

Trinidad - above (below) WTI

 

(14.40)

 

-

 

(12.40)

     

(12.52)

 

-

 

(11.40)

 

Other International - above (below) WTI

 

(8.00)

 

-

 

(2.00)

     

2.18

 

-

 

3.68

 

Natural Gas Liquids

                     

Realizations as % of WTI

 

34

%

-

 

46

%

   

32

%

-

 

35

%

Natural Gas ($/Mcf)

                     

Differentials

                     

United States - above (below) NYMEX Henry Hub

 

(0.60)

 

-

 

(0.20)

     

(0.54)

 

-

 

(0.43)

 

Realizations

                     

Trinidad

 

3.15

 

-

 

3.65

     

2.44

 

-

 

2.59

 

Other International

 

4.35

 

-

 

4.85

     

4.44

 

-

 

4.54

 

 

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

                     

 

 

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SOURCE EOG Resources, Inc.