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

11/05/2020

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


-