EOG
$36.65
Eog Resources
$.27
.74%
Earnings Details
2nd Quarter June 2020
Thursday, August 06, 2020 4:14:00 PM
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Summary

Eog Resources (EOG) Recent Earnings

Eog Resources (EOG) reported a 2nd Quarter June 2020 loss of $0.23 per share on revenue of $1.1 billion. The consensus estimate was a loss of $0.14 per share on revenue of $2.6 billion. Revenue fell 76.5% compared to the same quarter a year ago.

EOG Resources Inc explores for, develops, produces and markets crude oil and natural gas in the USA, Trinidad, United Kingdom, China, Argentina and, from time to time, select other international areas.

Results
Reported Earnings
($0.23)
Earnings Whisper
-
Consensus Estimate
($0.14)
Reported Revenue
$1.10 Bil
Revenue Estimate
$2.60 Bil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

EOG Resources Reports Second Quarter 2020 Results

HOUSTON, Aug. 6, 2020 /PRNewswire/ --

EOG Resources, Inc.

  • Generated Positive Net Cash Provided by Operating Activities and Free Cash Flow
  • Produced 7% More Crude Oil for 26% Less Capital Expenditures than Forecast
  • Per-Unit Cash Operating Costs Below Targets
  • Discovered 500 Bcf Net Natural Gas Resource Potential in Trinidad
  • Increased 2020 Well Cost Savings Target to 12% from 8%, Supporting Improved Outlook for Capital Efficiency

EOG Resources, Inc. (EOG) today reported a second quarter 2020 net loss of $909 million, or $1.57 per share, compared with second quarter 2019 net income of $848 million, or $1.46 per share.

Adjusted non-GAAP net loss for the second quarter 2020 was $131 million, or $0.23 per share, compared with adjusted non-GAAP net income of $762 million, or $1.31 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

Second Quarter 2020 Review

Earnings in the second quarter 2020 were lower than the same prior year period due to lower commodity prices and production volumes, partially offset by reduced operating costs. EOG adjusted quickly to the decline in commodity prices – a result of COVID-19's impact on demand – by slowing drilling activity and lowering both capital expenditures and operating costs. EOG also deferred production by delaying initial production from most new wells and shutting in production from lower-margin, existing wells across multiple basins. Deferring production volumes into higher-priced time periods is a return-based decision designed to maximize net present value.

As a result of EOG's actions to address the rapid change in market conditions, total company crude oil volumes were 331,100 barrels of oil per day (Bopd), 27 percent below the second quarter 2019. Natural gas liquids production was 23 percent lower and natural gas volumes were 15 percent lower, contributing to 23 percent lower total company daily production.

Net crude oil volumes associated with the shut-in of existing wells peaked at approximately 107,000 Bopd in May, with an average of approximately 73,000 Bopd shut in during the second quarter. The company estimates that approximately 25,000 Bopd will remain shut-in on average during the third quarter 2020. EOG began to return shut-in volumes to production in June, and expects nearly all shut-in wells to begin production before the end of the third quarter. EOG also deferred initial production from most new wells until late June, with ten net new wells contributing less than 1,000 Bopd of production in the second quarter. EOG continues to closely monitor market conditions and retains flexibility to adjust its plans in response to changes in commodity prices.

Lease and well, transportation, and gathering and processing costs each declined in the second quarter compared with the prior year period. Lease and well costs were the largest contributor to the overall cost reduction and were down eight percent on a per-unit basis. Sustainable efficiency improvements and service cost reductions contributed to the savings. These factors also contributed to an improved well cost reduction target of 12 percent for 2020, an increase from the forecast at the start of the year of eight percent.

During the second quarter, EOG received net cash from settlements of financial commodity derivative contracts of $639 million. The company also elected to sell a portion of its crude oil production in May and June under fixed-price agreements to further limit its exposure to commodity price volatility. This contributed to lower average crude oil prices compared with the prior year period and reduced revenues from gathering, processing and marketing relative to marketing costs.

Net cash provided by operating activities was $88 million. Changes in working capital and other assets and liabilities generated a net cash outflow of $1.0 billion in the second quarter 2020 and a net cash inflow of $0.2 billion in the first six months of 2020. Excluding changes in working capital and certain other items, EOG generated $672 million of discretionary cash flow in the second quarter 2020. The company incurred total expenditures of $534 million, including $478 million of capital expenditures before acquisitions, non–cash transactions and asset retirement costs, resulting in $194 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

"EOG generated positive free cash flow in the second quarter, made possible by our ability to quickly reduce activity and cut operating costs in all of our operating areas in response to historically low oil prices," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "This is a testament to EOG's unique culture and the flexibility provided by a decentralized organizational structure. In addition, our focus on safety, innovation, technical advancements and continuous improvement has not wavered. Our talented employees quickly and safely adapted to these volatile conditions, and I want to thank them for their dedication and commitment to EOG.

"Going forward, we will remain flexible and ready to respond to changes in market conditions with the goal of maximizing long-term shareholder value. Our priorities are unchanged: generate high returns on any capital invested and generate free cash flow to fund the dividend and protect our strong balance sheet. The sustainable improvements we are making across the company will support improved capital efficiency in the future, enabling EOG to maintain production at lower oil prices. We are confident EOG will emerge from the downturn an even better company."

Trinidad Exploration Success

EOG announced significant discoveries from its drilling campaign in Trinidad that have estimated gross resource potential of up to 1.0 trillion cubic feet of natural gas, or 500 billion cubic feet, net to EOG. The discoveries are based on results from four wells drilled in the past year located on three different blocks in shallow water off the southeast coast of Trinidad. The discoveries will support the installation of two new production platforms and development programs for the next three to five years. EOG plans to drill two additional wells over the remainder of 2020. Additional resource potential could be confirmed through further evaluation of the discovery wells and subsequent development. The exploration success supports EOG's long-term strategy in Trinidad of generating high returns and strong free cash flow through low-cost operations and targeted exploration.

Financial Review

EOG retains exceptional financial flexibility, with strong investment-grade credit ratings, low leverage ratios and ample liquidity. At June 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $2.4 billion of cash on the balance sheet at the end of the second quarter, EOG's net debt was $3.3 billion for a net debt-to-total capitalization ratio of 14 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of June 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

On April 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 that matured on that date. In addition, on April 14, 2020, EOG closed its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050. EOG received aggregate net proceeds from the sale, after deducting underwriting discounts and offering expenses, of approximately $1.48 billion. On June 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020 that matured on that date.

During the second quarter, EOG entered into offsetting contracts to lock-in the value of outstanding crude oil NYMEX WTI price swap contracts and other financial commodity derivative contracts effective from June through December 2020. As of June 30, EOG expects to receive net cash payments of $360 million from the settlement of these contracts over the remainder of 2020.

Second Quarter 2020 Results Webcast
Friday, August 7, 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 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 imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
  • EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and 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)


2Q 2020


2Q 2019


YTD 2020


YTD 2019

Operating Revenues and Other





Crude Oil and Condensate

614,627



2,528,866



2,680,125



4,729,269


Natural Gas Liquids

93,909



186,374



254,444



405,012


Natural Gas

141,696



269,892



351,460



604,864


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

(126,362)



177,300



1,079,411



156,720


Gathering, Processing and Marketing

362,786



1,501,386



1,401,432



2,787,040


Gains on Asset Dispositions, Net

13,233



8,009



29,693



4,173


Other, Net

3,485



25,803



24,501



69,194


Total

1,103,374



4,697,630



5,821,066



8,756,272










Operating Expenses








Lease and Well

245,346



347,281



575,005



683,572


Transportation Costs

151,728



174,101



360,024



350,623


Gathering and Processing Costs

96,767



112,643



225,249



223,938


Exploration Costs

27,283



32,522



66,960



68,846


Dry Hole Costs

87



3,769



459



3,863


Impairments

305,415



112,130



1,878,350



184,486


Marketing Costs

444,444



1,500,915



1,553,437



2,770,972


Depreciation, Depletion and Amortization

706,679



957,304



1,706,739



1,836,899


General and Administrative

131,855



121,780



246,128



228,452


Taxes Other Than Income

80,319



204,414



237,679



397,320


Total

2,189,923



3,566,859



6,850,030



6,748,971










Operating Income (Loss)

(1,086,549)



1,130,771



(1,028,964)



2,007,301


Other Income (Expense), Net

(4,500)



8,503



13,608



14,115


Income (Loss) Before Interest Expense and Income Taxes

(1,091,049)



1,139,274



(1,015,356)



2,021,416


Interest Expense, Net

54,213



49,908



98,903



104,814


Income (Loss) Before Income Taxes

(1,145,262)



1,089,366



(1,114,259)



1,916,602


Income Tax Provision (Benefit)

(235,878)



241,525



(214,688)



433,335


Net Income (Loss)

(909,384)



847,841



(899,571)



1,483,267










Dividends Declared per Common Share

0.3750



0.2875



0.7500



0.5075


Net Income (Loss) Per Share








Basic

(1.57)



1.47



(1.55)



2.57


Diluted

(1.57)



1.46



(1.55)



2.56


Average Number of Common Shares








Basic

578,719



577,460



578,581



577,333


Diluted

578,719



580,247



578,581



580,204


 

Wellhead Volumes and Prices

(Unaudited)


2Q 2020


2Q 2019


% Change


YTD 2020


YTD 2019


% Change













Crude Oil and Condensate Volumes (MBbld) (A)










United States

330.9



454.9



-27

%


406.8



445.1



-9

%

Trinidad

0.1



0.6



-83

%


0.3



0.7



-57

%

Other International (B)

0.1



0.2



-50

%


0.1






Total

331.1



455.7



-27

%


407.2



445.8



-9

%













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












United States

20.40



61.01



-67

%


36.17



58.63



-38

%

Trinidad

0.60



49.56



-99

%


27.75



46.62



-40

%

Other International (B)

48.78



55.07



-11

%


53.41



57.78



-8

%

Composite

20.40



60.99



-67

%


36.16



58.61



-38

%













Natural Gas Liquids Volumes (MBbld) (A)












United States

101.2



131.1



-23

%


131.2



125.4



5

%

Other International (B)












Total

101.2



131.1



-23

%


131.2



125.4



5

%













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












United States

10.20



15.63



-35

%


10.65



17.84



-40

%

Other International (B)












Composite

10.20



15.63



-35

%


10.65



17.84



-40

%













Natural Gas Volumes (MMcfd) (A)












United States

939



1,047



-10

%


1,039



1,025



1

%

Trinidad

174



273



-36

%


188



270



-30

%

Other International (B)

34



36



-6

%


35



37



-5

%

Total

1,147



1,356



-15

%


1,262



1,332



-5

%













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












United States

1.11



1.98



-44

%


1.32



2.37



-44

%

Trinidad

2.13



2.69



-21

%


2.15



2.80



-23

%

Other International (B)

4.36



4.25



2

%


4.34



4.31



1

%

Composite

1.36



2.19



-38

%


1.53



2.51



-39

%













Crude Oil Equivalent Volumes (MBoed) (D)












United States

588.5



760.4



-23

%


711.1



741.3



-4

%

Trinidad

29.2



46.1



-37

%


31.6



45.6



-31

%

Other International (B)

5.7



6.3



-10

%


6.1



6.4



-5

%

Total

623.4



812.8



-23

%


748.8



793.3



-6

%













Total MMBoe (D)

56.7



74.0



-23

%


136.3



143.6



-5

%













(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 June 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 per share data (Unaudited)


June 30,


December 31,


2020


2019

Current Assets




Cash and Cash Equivalents

2,416,501



2,027,972


Accounts Receivable, Net

943,354



2,001,658


Inventories

676,580



767,297


Assets from Price Risk Management Activities

207,019



1,299


Income Taxes Receivable

196,958



151,665


Other

156,979



323,448


Total

4,597,391



5,273,339



Property, Plant and Equipment




Oil and Gas Properties (Successful Efforts Method)

64,406,245



62,830,415


Other Property, Plant and Equipment

4,665,815



4,472,246


Total Property, Plant and Equipment

69,072,060



67,302,661


Less:  Accumulated Depreciation, Depletion and Amortization

(39,838,595)



(36,938,066)


Total Property, Plant and Equipment, Net

29,233,465



30,364,595


Deferred Income Taxes

1,846



2,363


Other Assets

1,388,969



1,484,311


Total Assets

35,221,671



37,124,608



Current Liabilities




Accounts Payable

1,281,166



2,429,127


Accrued Taxes Payable

193,763



254,850


Dividends Payable

217,004



166,273


Liabilities from Price Risk Management Activities



20,194


Current Portion of Long-Term Debt

21,121



1,014,524


Current Portion of Operating Lease Liabilities

252,642



369,365


Other

188,685



232,655


Total

2,154,381



4,486,988






Long-Term Debt

5,703,141



4,160,919


Other Liabilities

2,138,696



1,789,884


Deferred Income Taxes

4,837,896



5,046,101


Commitments and Contingencies








Stockholders' Equity




Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,386,649
     Shares Issued at June 30, 2020 and 582,213,016 Shares Issued at December
     31, 2019

205,824



205,822


Additional Paid in Capital

5,886,298



5,817,475


Accumulated Other Comprehensive Loss

(6,130)



(4,652)


Retained Earnings

14,312,493



15,648,604


Common Stock Held in Treasury, 142,025 Shares at June 30, 2020 and 298,820
     Shares at December 31, 2019

(10,928)



(26,533)


Total Stockholders' Equity

20,387,557



21,640,716


Total Liabilities and Stockholders' Equity

35,221,671



37,124,608


 

Cash Flows Statements

In thousands of USD (Unaudited)


2Q 2020


2Q 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)

(909,384)



847,841



(899,571)



1,483,267


Items Not Requiring (Providing) Cash








Depreciation, Depletion and Amortization

706,679



957,304



1,706,739



1,836,899


Impairments

305,415



112,130



1,878,350



184,486


Stock-Based Compensation Expenses

39,571



38,566



79,643



77,653


Deferred Income Taxes

(252,466)



217,970



(207,692)



324,294


Gains on Asset Dispositions, Net

(13,233)



(8,009)



(29,693)



(4,173)


Other, Net

8,986



2,487



171



5,439


Dry Hole Costs

87



3,769



459



3,863


Mark-to-Market Commodity Derivative Contracts








Total (Gains) Losses

126,362



(177,300)



(1,079,411)



(156,720)


Net Cash Received from Settlements of Commodity 
     Derivative Contracts

639,388



10,444



723,761



31,290


Other, Net

(365)



663



(720)



1,639


Changes in Components of Working Capital and Other Assets and
   Liabilities








Accounts Receivable

469,294



239,250



1,191,457



(69,746)


Inventories

(18,095)



7,720



84,575



(11,259)


Accounts Payable

(1,618,276)



(67,229)



(1,184,718)



126,853


Accrued Taxes Payable

(6,482)



(61,718)



(61,087)



53,280


Other Assets

194,682



494,322



252,978



487,387


Other Liabilities

1,675



(4,014)



(64,403)



(58,106)


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

414,236



72,347



282,154



(22,034)


Net Cash Provided by Operating Activities

88,074



2,686,543



2,672,992



4,294,312


Investing Cash Flows








Additions to Oil and Gas Properties

(423,982)



(1,507,024)



(1,990,033)



(3,446,497)


Additions to Other Property, Plant and Equipment

(24,591)



(55,918)



(147,366)



(116,881)


Proceeds from Sales of Assets

17,567



2,593



43,368



17,642


Changes in Components of Working Capital Associated with
     Investing Activities

(414,236)



(72,325)



(282,154)



22,056


Net Cash Used in Investing Activities

(845,242)



(1,632,674)



(2,376,185)



(3,523,680)


Financing Cash Flows








Long-Term Debt Borrowings

1,483,852





1,483,852




Long-Term Debt Repayments

(1,000,000)



(900,000)



(1,000,000)



(900,000)


Dividends Paid

(217,042)



(127,135)



(384,100)



(254,681)


Treasury Stock Purchased

(402)



(2,155)



(5,057)



(8,403)


Proceeds from Stock Options Exercised and Employee Stock
    Purchase Plan

8,548



8,292



8,614



8,695


Debt Issuance Costs

(2,635)



(4,902)



(2,635)



(4,902)


Repayment of Finance Lease Liabilities

(4,824)



(3,213)



(8,445)



(6,403)


Changes in Components of Working Capital Associated with
    Financing Activities



(22)





(22)


Net Cash Provided by (Used in) Financing Activities

267,497



(1,029,135)



92,229



(1,165,716)


Effect of Exchange Rate Changes on Cash

(680)



(59)



(507)



(65)


Increase (Decrease) in Cash and Cash Equivalents

(490,351)



24,675



388,529



(395,149)


Cash and Cash Equivalents at Beginning of Period

2,906,852



1,135,810



2,027,972



1,555,634


Cash and Cash Equivalents at End of Period

2,416,501



1,160,485



2,416,501



1,160,485


 

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)









2Q 2020


Before

Tax


Income Tax

Impact


After

Tax


Diluted

Earnings
per Share









Reported Net Loss (GAAP)

(1,145,262)



235,878



(909,384)



(1.57)


Adjustments:








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

126,362



(27,734)



98,628



0.17


Net Cash Received from Settlements of Commodity Derivative Contracts

639,388



(140,333)



499,055



0.86


Less: Gains on Asset Dispositions, Net

(13,233)



2,930



(10,303)



(0.02)


Add: Certain Impairments

239,167



(48,351)



190,816



0.33


Adjustments to Net Loss

991,684



(213,488)



778,196



1.34










Adjusted Net Loss (Non-GAAP)

(153,578)



22,390



(131,188)



(0.23)










Average Number of Common Shares (GAAP)








Basic







578,719


Diluted







578,719










Average Number of Common Shares (Non-GAAP)








Basic







578,719


Diluted







578,719





2Q 2019


Before

Tax


Income Tax
Impact


After

Tax


Diluted

Earnings
per Share









Reported Net Income (GAAP)

1,089,366



(241,525)



847,841



1.46


Adjustments:








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

(177,300)



38,930



(138,370)



(0.24)


Net Cash Received from Settlements of Commodity Derivative Contracts

10,444



(2,276)



8,168



0.01


Less: Gains on Asset Dispositions, Net

(8,009)



1,734



(6,275)



(0.01)


Add: Certain Impairments

65,289



(14,311)



50,978



0.09


Adjustments to Net Income

(109,576)



24,077



(85,499)



(0.15)










Adjusted Net Income (Non-GAAP)

979,790



(217,448)



762,342



1.31










Average Number of Common Shares (GAAP)








Basic







577,460


Diluted







580,247










Average Number of Common Shares (Non-GAAP)







577,460


Basic







580,247


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)

(1,114,259)



214,688



(899,571)



(1.55)


Adjustments:








Gains Mark-to-Market Commodity Derivative Contracts

(1,079,411)



236,909



(842,502)



(1.47)


Net Cash Received from Settlements of Commodity Derivative Contracts

723,761



(158,851)



564,910



0.98


Less: Gains on Asset Dispositions, Net

(29,693)



6,543



(23,150)



(0.04)


Add: Certain Impairments

1,755,483



(368,324)



1,387,159



2.40


Adjustments to Net Loss

1,370,140



(283,723)



1,086,417



1.87










Adjusted Net Income (Non-GAAP)

255,881



(69,035)



186,846



0.32










Average Number of Common Shares (GAAP)








Basic







578,581


Diluted







578,581










Average Number of Common Shares (Non-GAAP)








Basic







578,581


Diluted







580,179





YTD 2019


Before

Tax


Income Tax

Impact


After

Tax


Diluted

Earnings

per Share









Reported Net Income (GAAP)

1,916,602



(433,335)



1,483,267



2.56


Adjustments:








Gains on Mark-to-Market Commodity Derivative Contracts

(156,720)



34,397



(122,323)



(0.21)


Net Cash Received from Settlements of Commodity Derivative Contracts

31,290



(6,868)



24,422



0.04


Less: Gains on Asset Dispositions, Net

(4,173)



998



(3,175)



(0.01)


Add: Certain Impairments

89,034



(19,541)



69,493



0.12


Adjustments to Net Income

(40,569)



8,986



(31,583)



(0.06)










Adjusted Net Income (Non-GAAP)

1,876,033



(424,349)



1,451,684



2.50










Average Number of Common Shares (GAAP)








Basic







577,333


Diluted







580,204










Average Number of Common Shares (Non-GAAP)








Basic







577,333


Diluted







580,204


 

Discretionary Cash Flow and Free Cash Flow

In thousands of USD (Unaudited)









2Q 2020


2Q 2019


YTD 2020


YTD 2019









Net Cash Provided by Operating Activities (GAAP)

88,074



2,686,543



2,672,992



4,294,312










Adjustments:








Exploration Costs (excluding Stock-Based Compensation Expenses)

20,484



26,089



52,966



55,876


Other Non-Current Income Taxes - Net Receivable



42,764



112,704



145,682


Changes in Components of Working Capital and Other Assets and Liabilities








Accounts Receivable

(469,294)



(239,250)



(1,191,457)



69,746


Inventories

18,095



(7,720)



(84,575)



11,259


Accounts Payable

1,618,276



67,229



1,184,718



(126,853)


Accrued Taxes Payable

6,482



61,718



61,087



(53,280)


Other Assets

(194,682)



(494,322)



(252,978)



(487,387)


Other Liabilities

(1,675)



4,014



64,403



58,106


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

(414,236)



(72,347)



(282,154)



22,034


Discretionary Cash Flow (Non-GAAP)

671,524



2,074,718



2,337,706



3,989,495










Discretionary Cash Flow (Non-GAAP) - Percentage Decrease

-68

%




-41

%











Discretionary Cash Flow (Non-GAAP)

671,524



2,074,718



2,337,706



3,989,495


Less:








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

(477,616)



(1,595,726)



(2,162,336)



(3,328,202)


Free Cash Flow (Non-GAAP) (b)

193,908



478,992



175,370



661,293










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









Total Expenditures (GAAP)

534,411



1,663,127



2,360,189



3,765,046


Less:








Asset Retirement Costs

(5,955)



(55,425)



(25,563)



(60,581)


Non-Cash Expenditures of Other Property, Plant and Equipment

(60)



(586)



(60)



(586)


Non-Cash Acquisition Costs of Unproved Properties

(23,243)



(10,240)



(47,731)



(53,721)


Non-Cash Finance Leases

(24,319)





(73,277)




Acquisition Costs of Proved Properties

(3,218)



(1,150)



(51,222)



(321,956)


Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)

477,616



1,595,726



2,162,336



3,328,202










(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 six-month periods ending June 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

%











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 2014


FY 2013


FY 2012







Net Cash Provided by Operating Activities (GAAP)

8,649,155



7,329,414



5,236,777








Adjustments:






Exploration Costs (excluding Stock-Based Compensation Expenses)

157,453



134,531



159,182


Excess Tax Benefits from Stock-Based Compensation

99,459



55,831



67,035


Changes in Components of Working Capital and Other Assets and Liabilities






Accounts Receivable

(84,982)



23,613



178,683


Inventories

161,958



(53,402)



156,762


Accounts Payable

(543,630)



(178,701)



17,150


Accrued Taxes Payable

(16,486)



(75,142)



(78,094)


Other Assets

14,448



109,567



118,520


Other Liabilities

(75,420)



20,382



(36,114)


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

103,414



51,361



(74,158)


Discretionary Cash Flow (Non-GAAP)

8,465,369



7,417,454



5,745,743








Discretionary Cash Flow (Non-GAAP) - Percentage Increase

14

%


29

%









Discretionary Cash Flow (Non-GAAP)

8,465,369



7,417,454



5,745,743


Less:






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

(8,292,090)



(7,101,791)



(7,539,994)


Free Cash Flow (Non-GAAP) (b)

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, 2014, 2013 and 2012:







Total Expenditures (GAAP)

8,631,906



7,361,457



7,753,828


Less:






Asset Retirement Costs

(195,630)



(134,445)



(126,987)


Non-Cash Expenditures of Other Property, Plant and Equipment





(65,791)


Non-Cash Acquisition Costs of Unproved Properties

(5,085)



(5,007)



(20,317)


Acquisition Costs of Proved Properties

(139,101)



(120,214)



(739)


Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)

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)





















2Q 2020


2Q 2019


FY 2019


FY 2018


FY 2017











Exploration and Development Drilling

381



1,290



4,951



4,935



3,132


Facilities

31



174



629



625



575


Leasehold Acquisitions

30



38



276



488



427


Property Acquisitions

3



1



380



124



73


Capitalized Interest

8



11



38



24



27


Subtotal

453



1,514



6,274



6,196



4,234


Exploration Costs

27



33



140



149



145


Dry Hole Costs



4



28



5



5


Exploration and Development Expenditures

480



1,551



6,442



6,350



4,384


Asset Retirement Costs

5



56



186



70



56


Total Exploration and Development Expenditures

485



1,607



6,628



6,420



4,440


Other Property, Plant and Equipment

49



56



272



286



173


Total Expenditures

534



1,663



6,900



6,706



4,613


 

EBITDAX and Adjusted EBITDAX

In thousands of USD (Unaudited)









2Q 2020


2Q 2019


YTD 2020


YTD 2019









Net Income (Loss) (GAAP)

(909,384)



847,841



(899,571)



1,483,267










Adjustments:








Interest Expense, Net

54,213



49,908



98,903



104,814


Income Tax Provision (Benefit)

(235,878)



241,525



(214,688)



433,335


Depreciation, Depletion and Amortization

706,679



957,304



1,706,739



1,836,899


Exploration Costs

27,283



32,522



66,960



68,846


Dry Hole Costs

87



3,769



459



3,863


Impairments

305,415



112,130



1,878,350



184,486


EBITDAX (Non-GAAP)

(51,585)



2,244,999



2,637,152



4,115,510


(Gains) Losses on MTM Commodity Derivative Contracts

126,362



(177,300)



(1,079,411)



(156,720)


Net Cash Received from Settlements of Commodity Derivative Contracts

639,388



10,444



723,761



31,290


Less:  Gains on Asset Dispositions, Net

(13,233)



(8,009)



(29,693)



(4,173)










Adjusted EBITDAX (Non-GAAP)

700,932



2,070,134



2,251,809



3,985,907










Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

-66

%




-44

%











Definitions








EBITDAX - Earnings Before Interest Expense; Income Taxes; 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)













June 30,
2020


March 31,
2020


December 31,
2019


September 30,
2019


June 30,
2019


March 31,
2019












Total Stockholders' Equity - (a)

20,388



21,471



21,641



21,124



20,630



19,904














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

5,724



5,222



5,175



5,177



5,179



6,081


Less: Cash

(2,417)



(2,907)



(2,028)



(1,583)



(1,160)



(1,136)


Net Debt (Non-GAAP) - (c)

3,307



2,315



3,147



3,594



4,019



4,945














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

26,112



26,693



26,816



26,301



25,809



25,985














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

23,695



23,786



24,788



24,718



24,649



24,849














Debt-to-Total Capitalization (GAAP) - (b) /

    [(a) + (b)]

22

%


20

%


19

%


20

%


20

%


23

%













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

14

%


10

%


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 July 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 July 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 July 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



0.7

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


88,000



(1.16)

Sep-20


88,000



(1.16)

October 1, 2020 through December 31, 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 expects to pay net cash of $3.2 million for the settlement of these 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 July 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 expects to receive net cash of $364.0 million for the settlement of these 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 July 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 July 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 expects to receive net cash of $9.2 million for the settlement of these 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 July 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


50,000



2.75


 

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.  The net cash EOG received for settling these contracts was $7.8 million.  Presented below is a comprehensive summary of EOG's natural gas collar contracts through July 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



2.5



2









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 expects to receive net cash of $1.1 million 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 July 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 


Weighted Average Price Differential

(MMBtud)

 ($/MMBtu)

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


30,000



0.55


August 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.  The net cash EOG paid for settling these contracts was $0.4 million.  Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through July 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 July 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


Weighted Average Price Differential

(MMBtud)

 ($/MMBtu)

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


50,000



1.4







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 expects to pay net cash of $11.9 million for the settlement of these 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


YTD 2020







Cost per Barrel of Oil Equivalent (Boe) Calculation






Volume - Thousand Barrels of Oil Equivalent - (a)

79,548



56,733



136,281








Crude Oil and Condensate

2,065,498



614,627



2,680,125


Natural Gas Liquids

160,535



93,909



254,444


Natural Gas

209,764



141,696



351,460


Total Wellhead Revenues - (b)

2,435,797



850,232



3,286,029








Operating Costs






Lease and Well

329,659



245,346



575,005


Transportation Costs

208,296



151,728



360,024


Gathering and Processing Costs

128,482



96,767



225,249


General and Administrative

114,273



131,855



246,128


Taxes Other Than Income

157,360



80,319



237,679


Interest Expense, Net

44,690



54,213



98,903


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

982,760



760,228



1,742,988








Depreciation, Depletion and Amortization (DD&A)

1,000,060



706,679



1,706,739


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

1,982,820



1,466,907



3,449,727








Exploration Costs

39,677



27,283



66,960


Dry Hole Costs

372



87



459


Impairments

1,572,935



305,415



1,878,350


Total Exploration Costs

1,612,984



332,785



1,945,769


Less:  Certain Impairments (Non-GAAP)

(1,516,316)



(239,167)



(1,755,483)


Total Exploration Costs (Non-GAAP)

96,668



93,618



190,286








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

2,079,488



1,560,525



3,640,013








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

30.62



14.99



24.11








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

12.36



13.40



12.79








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

18.26



1.59



11.32








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

24.93



25.86



25.31








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

5.69



(10.87)



(1.20)








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

26.15



27.51



26.71








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

4.47



(12.52)



(2.60)


 

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


 

Costs 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)  Third Quarter and Full Year 2020 Forecast

The forecast items for the third 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 Third  Quarter and Full Year 2020


3Q 2020



FY 2020

















Daily Sales Volumes












Crude Oil and Condensate Volumes (MBbld)












United States


363.0


-


373.0




402.0


-


408.0


Trinidad


0.6


-


1.0




0.6


-


1.0


Other International



-


0.2





-


0.2


Total


363.6


-


374.2




402.6


-


409.2


Natural Gas Liquids Volumes (MBbld)












Total


125.0


-


135.0




130.0


-


140.0


Natural Gas Volumes (MMcfd)












United States


940


-


1,000




985


-


1,075


Trinidad


165


-


185




180


-


195


Other International


20


-


30




20


-


30


Total


1,125


-


1,215




1,185


-


1,300


Crude Oil Equivalent Volumes (MBoed)












United States


644.7


-


674.7




696.2


-


727.2


Trinidad


28.1


-


31.8




30.6


-


33.5


Other International


3.3


-


5.2




3.3


-


5.2


Total


676.1


-


711.7




730.1


-


765.9






















 

Quarter and Full Year Guidance

(Unaudited)


Estimated Ranges for Third Quarter and Full Year 2020


3Q 2020



FY 2020

















Capital Expenditures ($MM)


600


-


700




3,400


-


3,600


















Operating Costs












Unit Costs ($/Boe)












Lease and Well


4.20


-


4.70




4.10


-


4.50


Transportation Costs


2.70


-


3.10




2.50


-


2.90


Gathering and Processing


1.70




1.90




1.65




1.85


Depreciation, Depletion and Amortization


12.10




12.60




11.85




12.85


General and Administrative


2.25


-


2.35




1.85


-


1.95


















Expenses ($MM)












Exploration and Dry Hole


35


-


45




130


-


170


Impairment


80




90




290




330


Capitalized Interest


5


-


9




27


-


33


Net Interest


50


-


54




200


-


205


















Taxes Other Than Income (% of Wellhead Revenue)


7.0

%

-


9.0

%



7.0

%

-


8.0

%

















Income Taxes












Effective Rate


15

%

-


20

%



16

%

-


21

%

Current Tax (Benefit) / Expense ($MM)


(15)


-


25




(120)


-


(80)


















Pricing - (Refer to Benchmark Commodity Pricing in text)












Crude Oil and Condensate ($/Bbl)












Differentials












United States - above (below) WTI


(2.30)


-


(0.30)




(2.05)


-


(0.05)


Trinidad - above (below) WTI


(11.00)


-


(9.00)




(9.50)


-


(7.50)


Other International - above (below) WTI


(18.75)


-


(12.75)




2.00


-


7.00


Natural Gas Liquids












Realizations as % of WTI


29

%

-


41

%



30

%

-


36

%

Natural Gas ($/Mcf)












Differentials












United States - above (below) NYMEX Henry Hub


(0.70)


-


(0.30)




(0.80)


-


(0.20)


Realizations












Trinidad


2.10


-


2.70




2.30


-


3.00


Other International


4.00


-


4.50




3.85


-


4.85


 

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.