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EOG Resources Reports Excellent Fourth Quarter and Full Year 2019 Results

EOG Resources Reports Excellent Fourth Quarter and Full Year 2019 Results

February 28, 2020

EOG Resources Reports Excellent Fourth Quarter and Full Year 2019 Results; Announces 2020 Capital Program; Raises Dividend by 30 Percent

  • Increased Common Stock Dividend by 30 Percent to $1.50 Indicated Annual Rate
  • Earned $2.7 Billion Net Income in 2019, or $4.71 per Share
  • Generated $8.2 Billion Net Cash from Operating Activities and Significant Free Cash Flow
  • Exceeded Fourth Quarter and Full Year 2019 Crude Oil Production Target with Capital Expenditures Below Target
  • Lease and Well and DD&A Expense Rates Below Target in Fourth Quarter and Full Year 2019
  • Increased Proved Reserves by 14% and Replaced 253% of 2019 Production at $8.21 per Boe Finding Cost
  • $6.3 to $6.7 Billion Capital Program Targets 10 14% Crude Oil Volume Growth in 2020
  • 2020 Capital Program and Dividend Funded with Net Cash from Operating Activities at Oil Prices Below $50

HOUSTON EOG Resources, Inc. (EOG) today reported fourth quarter 2019 net income of $637 million, or $1.10 per share, compared with fourth quarter 2018 net income of $893 million, or

$1.54 per share. Net cash from operating activities for the fourth quarter 2019 was $1.8 billion. For the full year 2019, EOG reported net income of $2.7 billion, or $4.71 per share, compared with net income of $3.4 billion, or $5.89 per share, for the full year 2018. Net cash from operating activities for the full year 2019 was $8.2 billion.

Adjusted non GAAP net income for the fourth quarter 2019 was $787 million, or $1.35 per share, compared with adjusted non GAAP net income of $718 million, or $1.24 per share, for the same prior year period. Adjusted non GAAP net income for the full year 2019 was $2.9 billion, or $4.98 per share, compared with adjusted non GAAP net income of $3.2 billion, or

$5.54 per share, for the full year 2018.

Increased crude oil production from high return operating areas and reductions in per unit operating costs contributed to EOG’s strong fourth quarter 2019 financial results. Adjusted earnings per share, discretionary cash flow and adjusted EBITDAX increased in the fourth quarter 2019 compared with the same prior year period, demonstrating EOG’s resiliency and ability to overcome declines in commodity prices. Please refer to the attached tables for definitions and the reconciliation of non GAAP measures to GAAP measures.

Fourth Quarter and Full Year 2019 Operating Review

Capital efficiency improvements from increased well productivity and cost reductions across EOG’s premium plays supported strong operating and financial performance in 2019. United States crude oil volumes grew 15 percent to 455,500 barrels of oil per day (Bopd). Total company natural gas liquids production increased 16 percent, while total company natural gas volumes grew 12 percent.

Total crude oil volumes in the fourth quarter 2019 were 468,900 Bopd, which was above the midpoint of the target range and represents an eight percent increase compared with the same prior year period. Natural gas liquids and natural gas volumes increased by 17 percent and 15 percent, respectively, during this same period. EOG incurred total expenditures of $1.5 billion in the fourth quarter. Total cash capital expenditures before acquisitions of $1.4 billion were below the low end of the target range. Please refer to the attached tables for definitions and the reconciliation of non GAAP measures to GAAP measures.

EOG continued to lower operating costs during the fourth quarter 2019. Lease and well costs declined 13 percent, transportation costs fell five percent and depreciation, depletion and amortization (DD&A) expenses fell six percent, all on a per unit basis compared with the same prior year period. The company also continued to implement sustainable efficiency improvements to reduce well costs. The fourth quarter improvements brought full year 2019 well cost reductions to seven percent, two percentage points ahead of the target.

EOG generated $2.1 billion of discretionary cash flow in the fourth quarter 2019. After considering total cash capital expenditures before acquisitions of $1.4 billion, EOG generated free cash flow during the fourth quarter 2019 of $723 million. For the full year 2019, EOG generated $8.1 billion of discretionary cash flow and incurred total cash capital expenditures before acquisitions of $6.2 billion, resulting in free cash flow of $1.9 billion. Please refer to the attached tables for definitions and the reconciliation of non GAAP measures to GAAP measures. As is further explained in the attached reconciliation tables, EOG now defines its free cash flow for a period as its discretionary cash flow for such period less its total cash capital expenditures (before acquisitions) for such period (without regards to the dividends paid in such period).

EOG believes this definition of free cash flow is more consistent with that utilized by other companies in the industry.

“Year after year, EOG keeps getting better, delivering record operating performance in 2019. Significant capital efficiency improvements from strong well productivity and sustainable cost reductions allowed us to deliver higher production with less capital investment than we planned at the beginning of the year,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “We did this while generating substantial free cash flow, strengthening our financial position and increasing the dividend. This was the third consecutive year since our transition to premium drilling that EOG delivered double digit returns and production growth along with strong free cash flow.”

2020 Capital Plan

The purpose of EOG’s annual capital program is to generate high returns on investment and increase the company’s business value. Exploration and development expenditures for 2020 are expected to range from $6.3 billion to $6.7 billion, including facilities and gathering, processing and other expenditures, and excluding acquisitions and non cash exchanges. The disciplined capital program supports growth in crude oil production of 10 to 14 percent in 2020 and funds dividend payments with net cash from operating activities at less than $50 oil.

Due to the decline in crude oil prices, the 2020 capital plan allocates slightly less capital to growing oil production than in 2019. To continue to improve the company, the 2020 plan allocates more capital than in 2019 to fund new high quality drilling potential and high return infrastructure to further lower EOG’s cost structure and environmental footprint. With the benefit of sustainable cost reductions and operational efficiencies, EOG expects to complete approximately 800 net wells in 2020 compared with 750 net wells in 2019. Activity will remain focused in EOG’s highest rate of return oil assets in the Delaware Basin, Eagle Ford and Rocky Mountain Area.

“EOG’s 2020 capital plan reflects continued improvement in capital efficiency, highlights the resiliency of our business model, and ensures the capital program and dividend payments can be funded at a conservative oil price. Looking to the future, our 2020 plan also invests in new high return drilling potential and infrastructure development to lower costs and further improve the company,” Thomas said. “EOG’s sustainable competitive advantages already position us as one of the lowest cost oil producers in the global market and we are poised to extend our cost advantage well into the future.”

Dividend Increase

The board of directors declared a dividend of $0.375 per share on EOG’s Common Stock, an increase of 30 percent. The dividend will be payable April 30, 2020, to stockholders of record as of April 16, 2020. The indicated annual rate is $1.50 per share.

“EOG’s high return premium drilling program and our low cost structure allow us to continue upholding the commitment we have made to return more cash to shareholders. This latest dividend increase demonstrates the confidence we have in our ability to grow cash flow, generate high returns through our premium well strategy and improve our future inventory with high quality new drilling potential,” Thomas said.

Reserves

At year end 2019, total company net proved reserves were 3,329 million barrels of oil equivalent (MMBoe), a 14 percent increase compared with year end 2018. Net proved reserve additions from all sources, excluding revisions due to price, replaced 253 percent of EOG’s 2019 production at a finding and development cost of $8.21 per barrel of oil equivalent. Revisions due to price decreased net proved reserves by 60 MMBoe and asset divestitures decreased net proved reserves by five MMBoe. For more reserves detail and a reconciliation of non GAAP measures to GAAP measures please refer to the attached tables.

For the 32nd consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.

Financial Review

EOG further strengthened its financial position during the fourth quarter 2019. At December 31, 2019, EOG’s total debt outstanding was $5.2 billion for a debt to total capitalization ratio of 19 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $3.1 billion for a net debt to total capitalization ratio of 13 percent. For definitions and the reconciliation of non GAAP measures to GAAP measures, please refer to the attached tables.

Fourth Quarter 2019 Results Webcast

Friday, February 28, 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

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 fourth 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 fourth 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;
  • 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

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.

Financial Report

(Unaudited; in millions, except per share data)

Three Months Ended                                                Twelve Months Ended

                           December 31,                                                             December 31,                     

               2019                           2018                           2019                         2018           
Operating Revenues and Other $               4,320.2 $                     4,574.5 $              17,380.0 $              17,275.4
Net Income $                  636.5 $                        892.8 $                2,734.9 $                3,419.0
Net Income Per Share Basic  

$                     1.10

 

$                          1.55

 

$                     4.73

 

$                     5.93

Diluted $                     1.10 $                          1.54 $                     4.71 $                     5.89
Average Number of Common Shares

Basic

 

              578.2

   

                   577.0

   

              577.7

   

              576.6

Diluted               580.8                      580.3                 580.8                 580.4

 

 

Summary Income Statements (Unaudited; in thousands, except per share data)

 

  Three Months Ended Twelve Months Ended
                           December 31,                                                December 31,                         
            2019                                 2018                        2019                                  2018           
Operating Revenues and Other    
Crude Oil and Condensate $        2,464,274              $          2,383,326 $         9,612,532                $         9,517,440
Natural Gas Liquids 215,070                                266,037 784,818                           1,127,510
Natural Gas 309,606                                389,213 1,184,095                           1,301,537
Gains (Losses) on Mark-to-Market Commodity

Derivative Contracts

 

(62,347)                               132,095

 

180,275                             (165,640)

Gathering, Processing and Marketing 1,238,792                             1,331,105 5,360,282                           5,230,355
Gains on Asset Dispositions, Net 119,963                                  79,904 123,613                              174,562
Other, Net             34,888                                  (7,144)           134,358                               89,635
Total       4,320,246                             4,574,536      17,379,973                    17,275,399
Operating Expenses    
Lease and Well 334,538                                346,442 1,366,993                           1,282,678
Transportation Costs 208,312                                196,095 758,300                              746,876
Gathering and Processing Costs 127,615                                112,396 479,102                              436,973
Exploration Costs 36,495                                  33,862 139,881                              148,999
Dry Hole Costs –                                       145 28,001                                  5,405
Impairments 228,135                                186,087 517,896                              347,021
Marketing Costs 1,237,259                             1,349,416 5,351,524                           5,203,243
Depreciation, Depletion and Amortization 959,208                                919,963 3,749,704                           3,435,408
General and Administrative 125,187                                116,904 489,397                              426,969
Taxes Other Than Income           199,746                               190,086           800,164                             772,481
Total       3,456,495                             3,451,396      13,680,962                    12,806,053
Operating Income 863,751                             1,123,140 3,699,011                           4,469,346
Other Income, Net               8,152                                 21,220             31,385                               16,704
Income Before Interest Expense and Income Taxes 871,903                             1,144,360 3,730,396                           4,486,050
Interest Expense, Net             40,695                                 56,020           185,129                             245,052
Income Before Income Taxes 831,208                             1,088,340 3,545,267                           4,240,998
Income Tax Provision           194,687                               195,572           810,357                             821,958
Net Income $            636,521              $                 892,768 $         2,734,910                $         3,419,040
Dividends Declared per Common Share $              0.2875              $                   0.2200 $              1.0825                $              0.8100

 

EOG RESOURCES, INC.

Operating Highlights (Unaudited)

 

  Three Months Ended   Twelve Months Ended  
                    December 31,                                      December 31,               
           2019                           2018             % Change            2019                           2018             % Change
Wellhead Volumes and Prices        
Crude Oil and Condensate Volumes (MBbld) (A)        
United States 468.3                         430.3 9% 455.5                         394.8 15%
Trinidad 0.5                             0.8 -38% 0.6                             0.8 -25%
Other International (B)                   0.1                           4.5 -98%                   0.1                           4.3 -98%
Total                468.9                         435.6 8% 456.2                         399.9 14%
 

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

United States $                57.14 $                59.37 -4% $                57.74 $                65.16 -11%
Trinidad 46.73 51.80 -10% 47.16 57.26 -18%
Other International (B) 53.76 70.44 -24% 57.40 71.45 -20%
Composite 57.13 59.47 -4% 57.72 65.21 -11%
 

Natural Gas Liquids Volumes (MBbld) (A)

           
United States 144.0 122.8 17% 134.1 116.1 16%
Other International (B)                       –                       –                         –                       –  
Total                144.0 122.8 17% 134.1 116.1 16%
 

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

         
United States $                16.23 $                23.54 -31% $                16.03 $                26.60 -40%
Other International (B)    
Composite 16.23 23.54 -31% 16.03 26.60 -40%
 

Natural Gas Volumes (MMcfd) (A)

           
United States 1,148 974 18% 1,069 923 16%
Trinidad 242 230 5% 260 266 -2%
Other International (B)                    35                    32 9%                    37                    30 23%
Total                1,425 1,236 15% 1,366 1,219 12%
 

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

         
United States $                 2.20 $                 3.50 -37% $                 2.22 $                 2.88 -23%
Trinidad 2.78 3.03 -8% 2.72 2.94 -7%
Other International (B) 4.88 4.02 22% 4.44 4.08 9%
Composite 2.36 3.42 -31% 2.38 2.92 -19%
 

Crude Oil Equivalent Volumes (MBoed) (D)

           
United States 803.6 715.5 12% 767.8 664.7 16%
Trinidad 40.9 39.0 5% 44.0 45.1 -2%
Other International (B)                   5.8                  10.0 -42%                   6.2                   9.4 -34%
Total                850.3 764.5 11% 818.0 719.2 14%

 

Total MMBoe (D)                                                                             78.2                           70.3                11%                                                                                                   298.6                         262.5               14%

 

  • Thousand barrels per day or million cubic feet per day, as
  • Other International includes EOG’s United Kingdom, China and Canada The United Kingdom operations were sold in the fourth quarter of 2018.
  • Dollars per barrel or per thousand cubic feet, as Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG’s Annual Report on Form 10-K for the year ended December 31, 2019).
  • Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural 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.

 

Summary Balance Sheets (Unaudited; in thousands, except share data)

 

  December 31, December 31,
              2019                            2018             
  ASSETS    
Current Assets      
Cash and Cash Equivalents   $              2,027,972 $              1,555,634
Accounts Receivable, Net   2,001,658 1,915,215
Inventories   767,297 859,359
Assets from Price Risk Management Activities   1,299 23,806
Income Taxes Receivable   151,665 427,909
Other                  323,448                275,467
Total   5,273,339 5,057,390
 

Property, Plant and Equipment

     
Oil and Gas Properties (Successful Efforts Method) 62,830,415 57,330,016
Other Property, Plant and Equipment             4,472,246             4,220,665
Total Property, Plant and Equipment 67,302,661 61,550,681
Less: Accumulated Depreciation, Depletion and Amortization          (36,938,066)          (33,475,162)
Total Property, Plant and Equipment, Net 30,364,595 28,075,519
Deferred Income Taxes 2,363 777
Other Assets             1,484,311                800,788
Total Assets $            37,124,608 $            33,934,474

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Accounts Payable $              2,429,127 $              2,239,850
Accrued Taxes Payable 254,850 214,726
Dividends Payable 166,273 126,971
Liabilities from Price Risk Management Activities 20,194
Current Portion of Long-Term Debt 1,014,524 913,093
Current Portion of Operating Lease Liabilities 369,365
Other                232,655                233,724
Total 4,486,988 3,728,364

 

 

Long-Term Debt 4,160,919 5,170,169
Other Liabilities 1,789,884 1,258,355
Deferred Income Taxes Commitments and Contingencies 5,046,101 4,413,398
Stockholders’ Equity    
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and
582,213,016 Shares and 580,408,117 Shares Issued

at December 31, 2019 and 2018, respectively

 

205,822

 

205,804

Additional Paid in Capital 5,817,475 5,658,794
Accumulated Other Comprehensive Loss (4,652) (1,358)
Retained Earnings 15,648,604 13,543,130
Common Stock Held in Treasury, 298,820 Shares and

385,042 Shares at December 31, 2019 and 2018, respectively

 

                (26,533)

 

                (42,182)

Total Stockholders’ Equity           21,640,716           19,364,188
Total Liabilities and Stockholders’ Equity $            37,124,608 $            33,934,474

 

EOG RESOURCES, INC.

Summary Statements of Cash Flows (Unaudited; in thousands)

 
 

 

 

Cash Flows from Operating Activities

Three Months Ended

                     December 31,                     

           2019                              2018           

Twelve Months Ended

                     December 31,                     

           2019                              2018           

Reconciliation of Net Income to Net Cash Provided by Operating Activities:    
Net Income $           636,521             $           892,768 $     2,734,910             $ 3,419,040
Items Not Requiring (Providing) Cash    
Depreciation, Depletion and Amortization 959,208                         919,963 3,749,704                      3,435,408
Impairments 228,135                         186,087 517,896                         347,021
Stock-Based Compensation Expenses 42,415                           39,047 174,738                         155,337
Deferred Income Taxes 123,082                         212,454 631,658                         894,156
Gains on Asset Dispositions, Net (119,963)                         (79,904) (123,613)                      (174,562)
Other, Net 341                           (8,248) 4,496                             7,066
Dry Hole Costs –                                    145 28,001                              5,405
Mark-to-Market Commodity Derivative Contracts    
Total (Gains) Losses 62,347                        (132,095) (180,275)                        165,640
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 91,521                          (78,678) 231,229                        (258,906)
Other, Net (253)                           1,456 962                             3,108
Changes in Components of Working Capital and Other Assets and Liabilities    
Accounts Receivable (85,937)                        185,349 (91,792)                      (368,180)
Inventories 34,686                        (108,591) 90,284                        (395,408)
Accounts Payable 34,286                          (98,178) 168,539                         439,347
Accrued Taxes Payable (47,925)                        (55,570) 40,122                          (92,461)
Other Assets (36,572)                        (22,101) 358,001                        (125,435)
Other Liabilities (38,304)                          25,725 (56,619)                         10,949
Changes in Components of Working Capital Associated with Investing and Financing    
Activities           (76,384)          205,599        (115,061)          301,083
Net Cash Provided by Operating Activities 1,807,204 2,085,228 8,163,180 7,768,608
Investing Cash Flows        
Additions to Oil and Gas Properties (1,285,003) (1,267,362) (6,151,885) (5,839,294)
Additions to Other Property, Plant and Equipment (83,291) (34,797) (270,641) (237,181)
Proceeds from Sales of Assets 104,883 215,864 140,292 227,446
Other Investing Activities (10,000) (10,000) (19,993)
Changes in Components of Working Capital Associated with Investing Activities            76,384        (205,599)          115,061        (301,140)
Net Cash Used in Investing Activities (1,197,027) (1,291,894) (6,177,173) (6,170,162)
Financing Cash Flows        
Long-Term Debt Repayments (350,000) (900,000) (350,000)
Dividends Paid (167,349) (126,970) (588,200) (438,045)
Treasury Stock Purchased (2,914) (4,898) (25,152) (63,456)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 8,388 8,462 17,946 20,560
Debt Issuance Costs (5,016)
Repayment of Finance Lease Obligation (3,261) (3,167) (12,899) (8,219)
Changes in Components of Working Capital Associated with Financing Activities                   –                         –                         –                          57
Net Cash Used in Financing Activities (165,136) (476,573) (1,513,321) (839,103)
Effect of Exchange Rate Changes on Cash                 (174)           (35,259)                 (348)           (37,937)
Increase in Cash and Cash Equivalents 444,867 281,502 472,338 721,406
Cash and Cash Equivalents at Beginning of Period      1,583,105      1,274,132      1,555,634          834,228
Cash and Cash Equivalents at End of Period $ 2,027,972 $ 1,555,634 $ 2,027,972 $ 1,555,634

 

Fourth Quarter 2019 Well Results by Play (Unaudited)

 

        Wells On Line                                               Initial Gross 30-Day Average Production Rate                              

 

    Lateral Length Crude Oil and

Condensate

  Natural Gas

Liquids

   

Natural Gas

  Crude Oil

Equivalent

    Gross              Net             (ft)      (Bbld) (A)   (Bbld) (A)   (MMcfd) (A)   (Boed) (B)
Delaware Basin                  
Wolfcamp 23                 20 9,400 2,500   750   3.7   3,850
Bone Spring 17                 15 8,000 1,850   450   2.3   2,700
Leonard 11                 11 8,000 2,350   900   4.6   4,000
South Texas Eagle Ford 67                 64 7,400 1,100   150   0.6   1,350
South Texas Austin Chalk 9                   9 6,100 1,650   300   1.4   2,200
Powder River Basin                  
Turner / Parkman 7                   6 8,900 900   150   3.5   1,650
Niobrara 1                   1 8,800 950   50   0.7   1,100
DJ Basin Codell / Niobrara 12                 11 11,400 850   50   0.4   950
Williston Basin Bakken/Three Forks 6                   5 10,100 2,250   250   1.9   2,800

 

 

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

 

EOG RESOURCES, INC.

Reconciliation of Adjusted Net Income (Unaudited; in thousands, except per share data)

 

 

The following chart adjusts the three-month and twelve-month periods ended December 31, 2019 and 2018 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions in 2019 and 2018, to add back impairment charges related to certain of EOG’s assets in 2019 and 2018 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

 

Three Months Ended                                                        Three Months Ended

                            December 31, 2019                                                          December 31, 2018                          

 

   

Before

       Tax     

Income Tax

      Impact   

 

After

        Tax     

Diluted Earnings

  per Share

 

Before

        Tax     

Income Tax

      Impact   

 

After

        Tax     

Diluted Earnings

  per Share

Reported Net Income (GAAP)   $ 831,208   $ (194,687)   $ 636,521   $      1.10   $ 1,088,340   $ (195,572)   $ 892,768   $      1.54
Adjustments:                

(Gains) Losses on Mark-to-Market Commodity

Derivative Contracts                                                            62,347           (13,684)           48,663             0.08            (132,095)           29,096         (102,999) (0.18)

Net Cash Received from (Payments for)

Settlements of Commodity Derivative  
Contracts 91,521   (20,087)   71,434   0.12   (78,678)   17,330   (61,348)   (0.11)
Less: Gains on Asset Dispositions, Net (119,963)   26,342   (93,621)   (0.16)   (79,904)   13,625   (66,279)   (0.11)
Add: Impairments 158,725   (34,837)   123,888   0.21   131,795   (29,031)   102,764   0.18
Less: Tax Reform Impact              –                             –                            –                          –                           –                      (46,684)           (46,684)            (0.08)
Adjustments to Net Income        192,630           (42,266)          150,364            0.25          (158,882)          (15,664)         (174,546)            (0.30)
Adjusted Net Income (Non-GAAP)   $ 1,023,838     $ (236,953)     $ 786,885     $      1.35     $ 929,458     $ (211,236)     $ 718,222     $      1.24
 

Average Number of Common Shares (GAAP) Basic

             

 

578,219

               

 

577,035

Diluted             580,849               580,288

 

Twelve Months Ended                                                      Twelve Months Ended

                            December 31, 2019                                                          December 31, 2018                          

 

   

Before

       Tax     

Income Tax

      Impact   

 

After

        Tax     

Diluted Earnings

  per Share

 

Before

        Tax     

Income Tax

      Impact   

 

After

        Tax     

Diluted Earnings

  per Share

Reported Net Income (GAAP)   $ 3,545,267   $ (810,357)   $ 2,734,910   $      4.71   $ 4,240,998   $ (821,958)   $ 3,419,040   $      5.89
Adjustments:                

(Gains) Losses on Mark-to-Market Commodity

Derivative Contracts                                            (180,275)           39,567          (140,708)           (0.24)            165,640           (36,486)         129,154    0.22

Net Cash Received from (Payments for)

Settlements of Commodity Derivative  
Contracts 231,229   (50,750)   180,479   0.31   (258,906)   57,029   (201,877)   (0.35)
Less: Gains on Asset Dispositions, Net (123,613)   27,252   (96,361)   (0.17)   (174,562)   37,860   (136,702)   (0.24)
Add: Impairments 274,974   (60,351)   214,623   0.37   152,671   (33,629)   119,042   0.21
Less: Tax Reform Impact              –                             –                            –                          –                           –                     (110,335)         (110,335)            (0.19)
Adjustments to Net Income        202,315           (44,282)          158,033            0.27          (115,157)          (85,561)         (200,718)            (0.35)
Adjusted Net Income (Non-GAAP)   $ 3,747,582     $ (854,639)     $ 2,892,943     $      4.98     $ 4,125,841     $ (907,519)     $ 3,218,322     $      5.54
 

Average Number of Common Shares (GAAP) Basic

             

 

577,670

               

 

576,578

Diluted             580,777               580,441

 

Reconciliation of Discretionary Cash Flow (Unaudited; in thousands)

 

Calculation of Free Cash Flow (Unaudited; in thousands)

 

The following chart reconciles the three-month periods ended December 31, 2019 and 2018 and twelve-month periods ended December 31, 2019, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes – Net (Payable) Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the three months ended December 31, 2019 and 2018 and twelve months ended December 31, 2019, 2018 and 2017. EOG management uses this information for comparative purposes within the industry.

 

 

Three Months Ended                                                                                Twelve Months Ended

                              December 31,                                                                                               December 31,                        

               2019                                        2018                                         2019                                       2018                                         2017               

 

Net Cash Provided by Operating Activities (GAAP) $              1,807,204 $              2,085,228 $              8,163,180 $              7,768,608 $              4,265,336
Adjustments:          
Exploration Costs (excluding Stock-Based Compensation Expenses) 28,483 27,270 113,733 123,986 122,688
Other Non-Current Income Taxes – Net (Payable) Receivable 59,174 86,572 238,711 148,993 (513,404)
Changes in Components of Working Capital and Other Assets          
and Liabilities          
Accounts Receivable 85,937 (185,349) 91,792 368,180 392,131
Inventories (34,686) 108,591 (90,284) 395,408 174,548
Accounts Payable (34,286) 98,178 (168,539) (439,347) (324,192)
Accrued Taxes Payable 47,925 55,570 (40,122) 92,461 63,937
Other Assets 36,572 22,101 (358,001) 125,435 658,609
Other Liabilities 38,304 (25,725) 56,619 (10,949) 89,871
Changes in Components of Working Capital Associated with          
Investing and Financing Activities                   76,384               (205,599)                 115,061               (301,083)                  (89,992)
Discretionary Cash Flow (Non-GAAP) $             2,111,011 $             2,066,837 $             8,122,150 $             8,271,692 $             4,839,532
 

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

 

2%

   

-2%

 

71%

 
 

Discretionary Cash Flow (Non-GAAP)

 

$              2,111,011

 

$              2,066,837

 

$              8,122,150

 

$              8,271,692

 

4,839,532

Less:          
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a)            (1,388,233)            (1,302,999)            (6,234,454)            (6,172,950)            (4,228,859)
Free Cash Flow (Non-GAAP) (b) $                 722,778 $                 763,838 $             1,887,696 $             2,098,742 $                 610,673

 

 

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

 

Total Expenditures (GAAP) $              1,506,061 $              1,504,438 $              6,900,450 $              6,706,359 $              4,612,746
Less:          
Asset Retirement Costs (34,537) (27,910) (186,088) (69,699) (55,592)
Non-Cash Expenditures of Other Property, Plant and Equipment (1,680) (547) (2,266) (49,484)
Non-Cash Acquisition Costs of Unproved Properties (33,317) (128,719) (97,704) (290,542) (255,711)
Acquisition Costs of Proved Properties                  (48,294)                  (44,263)               (379,938)               (123,684)                  (72,584)
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) $             1,388,233 $              1,302,999 $             6,234,454 $             6,172,950 $             4,228,859

 

 

  • To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item for the three- month and twelve-month periods ending December 31, 2019. The comparative prior periods have been revised for this change in

 

Maintenance Capital Expenditures

 

The capital expenditures required to fund drilling as well as infrastructure requirements to keep oil production flat relative to 2019 across all premium oil plays.

 

EOG RESOURCES, INC.

Reconciliation of Discretionary Cash Flow (Unaudited; in thousands)

 

Calculation of Free Cash Flow (Unaudited; in thousands)

 

The following chart reconciles the twelve-month periods ended December 31, 2014, 2013 and 2012 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2014, 2013 and 2012. EOG management uses this information for comparative purposes within the industry.

 

 

    Twelve Months Ended

December 31,

 
            2014                       2013                       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)

 

  • 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

 

  • To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item. The comparative prior periods presented herein have been revised for this change in

 

 

Maintenance Capital Expenditures

 

The capital expenditures required to fund drilling as well as infrastructure requirements to keep oil production flat relative to 2019 across all premium oil plays.

 

Total Expenditures (Unaudited; in millions)

 

Three Months Ended                                         Twelve Months Ended

                 December 31,                                                      December 31,           

         2019                      2018                      2019                       2018                       2017        

 

Exploration and Development Drilling $            1,086 $         1,092 $           4,951 $          4,935 $           3,132
Facilities 130 107 629 625 575
Leasehold Acquisitions 75 157 276 488 427
Property Acquisitions 48 45 380 124 73
Capitalized Interest                     10                     6                     38                    24                    27
Subtotal 1,349 1,407 6,274 6,196 4,234
Exploration Costs 37 34 140 149 145
Dry Hole Costs                        –                      –                     28                      5                      5
Exploration and Development Expenditures 1,386 1,441 6,442 6,350 4,384
Asset Retirement Costs                     35                   28                   186                    70                    56
Total Exploration and Development Expenditures 1,421 1,469 6,628 6,420 4,440
Other Property, Plant and Equipment                     85                   35                   272                  286                  173
Total Expenditures   $            1,506   $         1,504   $            6,900   $          6,706   $          4,613

 

Reconciliation of Adjusted EBITDAX (Unaudited; in thousands)

 

The following chart adjusts the three-month and twelve-month periods ended December 31, 2019 and 2018 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the gains on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

 

 

Three Months Ended                              Twelve Months Ended

                  December 31,                                          December 31,            

         2019                        2018                         2019                         2018        

 

Net Income (GAAP) $        636,521 $         892,768 $     2,734,910 $     3,419,040
Adjustments:

Interest Expense, Net

 

40,695

 

56,020

 

185,129

 

245,052

Income Tax Provision 194,687 195,572 810,357 821,958
Depreciation, Depletion and Amortization 959,208 919,963 3,749,704 3,435,408
Exploration Costs 36,495 33,862 139,881 148,999
Dry Hole Costs 145 28,001 5,405
Impairments       228,135        186,087       517,896       347,021
EBITDAX (Non-GAAP) 2,095,741 2,284,417 8,165,878 8,422,883
Total (Gains) Losses on MTM Commodity Derivative Contracts 62,347 (132,095) (180,275) 165,640
Net Cash Received from (Payments for) Settlements of Commodity

Derivative Contracts

 

91,521

 

(78,678)

 

231,229

 

(258,906)

Gains on Asset Dispositions, Net      (119,963)         (79,904)      (123,613)      (174,562)
Adjusted EBITDAX (Non-GAAP) $ 2,129,646 $ 1,993,740 $ 8,093,219 $ 8,155,055
 

Adjusted EBITDAX (Non-GAAP) – Percentage Increase/Decrease

 

7%

   

-1%

 

 

Reconciliation of Net Debt and Total Capitalization Calculation of Net Debt-to-Total Capitalization Ratio (Unaudited; in millions, except ratio data)

 

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

 

At December 31,

        2019                  2018                 2017                 2016       
Total Stockholders’ Equity – (a)                                                                 $                                                                                                             21,641   $        19,364   $        16,283   $        13,982
Current and Long-Term Debt (GAAP) – (b) 5,175   6,083   6,387   6,986
Less: Cash              (2,028)                (1,556)                  (834)                (1,600)
Net Debt (Non-GAAP) – (c)               3,147                 4,527                 5,553                 5,386
Total Capitalization (GAAP) – (a) + (b)   $        26,816   $        25,447   $         22,670   $        20,968
 

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

 

  $        24,788

   

$        23,891

   

$         21,836

   

$        19,368

 

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

 

                19%

   

24%

   

28%

   

33%

 

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

 

                13%

   

19%

   

25%

   

28%

 

Reserves Supplemental Data (Unaudited)

 

2019 NET PROVED RESERVES RECONCILIATION SUMMARY

United                                  Other

     States          Trinidad     International        Total     

CRUDE OIL AND CONDENSATE (MMBbl)

Beginning Reserves                                                           1,531.7               0.4                  0.2          1,532.3

Revisions                                                                              (43.0)               0.1                  –                  (42.9)

Purchases in Place                                                                   2.9                –                      –                     2.9

Extensions, Discoveries and Other Additions                         370.0                –                      –                 370.0

Sales in Place                                                                         (1.3)               –                      –                    (1.3) Production                                                                          (166.3)              (0.2)                                                                                    (0.1)     (166.6)

Ending Reserves                                                            1,694.0               0.3                  0.1          1,694.4

 

 

NATURAL GAS LIQUIDS (MMBbl)

Beginning Reserves                                                             614.3                –                      –                 614.3

Revisions                                                                                 5.4                –                      –                     5.4

Purchases in Place                                                                   2.0                –                      –                     2.0

Extensions, Discoveries and Other Additions                         167.8                –                      –                 167.8

Sales in Place                                                                         (0.9)              –               –               (0.9) Production                                                                    (48.9)———————————————-          (48.9)

Ending Reserves                                                               739.7                –                      –                 739.7

 

 

NATURAL GAS (Bcf)

Beginning Reserves                                                           4,390.6            237.0               59.6          4,687.2

Revisions                                                                            (184.4)             47.0                 2.6            (134.8)

Purchases in Place                                                                 71.7                –                      –                   71.7

Extensions, Discoveries and Other Additions                       1,175.9              87.5                                                                                                 9.7 1,273.1 Sales in Place                                                                                    (14.5)               –                      –                  (14.5) Production                                                                          (404.5)            (95.4)                                                                                    (13.1)                       (513.0)

Ending Reserves                                                            5,034.8            276.1               58.8          5,369.7

 

 

OIL EQUIVALENTS (MMBoe)

Beginning Reserves                                                           2,877.8              39.9               10.1          2,927.8

Revisions                                                                              (68.3)               7.9                  0.4              (60.0)

Purchases in Place                                                                 16.8                –                      –                   16.8

Extensions, Discoveries and Other Additions                         733.7              14.6                 1.7             750.0

Sales in Place                                                                         (4.6)               –                      –                    (4.6) Production                                                                          (282.6)            (16.1)                                                                                    (2.2)     (300.9)

Ending Reserves                                                            3,272.8              46.3               10.0          3,329.1

 

 

Net Proved Developed Reserves (MMBoe)

At December 31, 2018                                                1,503.4              37.7                 7.0          1,548.1

At December 31, 2019                                                1,684.2              29.9                 7.1          1,721.2

 

2019 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions)

United                                  Other

     States          Trinidad     International        Total     

 

Acquisition Cost of Unproved Properties $     276.1 $        – $          – $     276.1
Exploration Costs 213.5 46.6 13.2 273.3
Development Costs       5,480.7           24.0              8.1       5,512.8
Total Drilling 5,970.3 70.6 21.3 6,062.2
Acquisition Cost of Proved Properties 379.9 379.9
Asset Retirement Costs          181.1             1.0              4.0          186.1
Total Exploration and Development Expenditures 6,531.3 71.6 25.3 6,628.2
Gathering, Processing and Other          269.7             2.4              0.1          272.2
Total Expenditures 6,801.0 74.0 25.4 6,900.4
Proceeds from Sales in Place         (140.3)             –                   –              (140.3)
Net Expenditures   $ 6,660.7 $      74.0 $        25.4 $ 6,760.1
RESERVE REPLACEMENT COSTS ($ / Boe ) *        
All-in Total, Net of Revisions $       9.09 $      3.14 $      10.14 $       8.90
All-in Total, Excluding Revisions Due to Price $       8.36 $      3.14 $      10.14 $       8.21
RESERVE REPLACEMENT *        
Drilling Only 260% 91% 77% 249%
All-in Total, Net of Revisions and Dispositions 240% 140% 95% 233%
All-in Total, Excluding Revisions Due to Price 261% 140% 95% 253%
All-in Total, Liquids 234% 50% 0% 233%

* See attached reconciliation schedule for calculation methodology

 

Reconciliation of Total Exploration and Development Expenditures Calculation of Reserve Replacement Costs ($ / BOE)

(Unaudited; in millions, except ratio data)

 

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflects total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.   Please note that the actual cost of adding reserves will vary from the   reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

 

For the Twelve Months Ended December 31, 2019  

United

     States

   

Other

   Trinidad     International       Total    

 

Total Costs Incurred in Exploration and Development Activities (GAAP)

 

$ 6,531.3

   

$      71.6      $       25.3      $ 6,628.2

Less: Asset Retirement Costs (181.1)   (1.0)               (4.0)          (186.1)
Non-Cash Acquisition Costs of Unproved Properties (97.7)   –                     –                 (97.7)
Total Acquisition Cost of Proved Properties        (379.9)               –                    –               (379.9)
Total Exploration and Development Expenditures for Drilling Only (Non-

GAAP) – (a)

 

  $ 5,872.6

   

$      70.6      $       21.3      $ 5,964.5

 

Total Costs Incurred in Exploration and Development Activities (GAAP)

 

$ 6,531.3

   

$      71.6      $       25.3      $ 6,628.2

Less: Asset Retirement Costs (181.1)   (1.0)               (4.0)          (186.1)
Non-Cash Acquisition Costs of Unproved Properties (97.7)   –                     –                 (97.7)
Non-Cash Acquisition Costs of Proved Properties          (52.3)               –                    –                 (52.3)
Total Exploration and Development Expenditures (Non-GAAP) – (b)   $ 6,200.2   $      70.6      $       21.3      $ 6,292.1
 

Total Expenditures (GAAP)

 

$ 6,801.0

   

$      74.0      $       25.4      $ 6,900.4

Less: Asset Retirement Costs (181.1)   (1.0)               (4.0)          (186.1)
Non-Cash Acquisition Costs of Unproved Properties (97.7)   –                     –                 (97.7)
Non-Cash Acquisition Costs of Proved Properties (52.3)   –                     –                 (52.3)
Non-Cash Capital – Other Miscellaneous            (1.6)               –                    –                  (1.6)
Total Cash Expenditures (Non-GAAP)   $ 6,468.3   $      73.0      $       21.4      $ 6,562.7
 

Net Proved Reserve Additions From All Sources – Oil Equivalents

     
Revisions Due to Price – (c) (59.7)   –                     –                 (59.7)
Revisions Other Than Price (8.6)   7.9                 0.4               (0.3)
Purchases in Place 16.8   –                     –                  16.8
Extensions, Discoveries and Other Additions – (d)         733.7             14.6                 1.7            750.0
Total Proved Reserve Additions – (e) 682.2   22.5                 2.1            706.8
Sales in Place            (4.6)               –                    –                  (4.6)
Net Proved Reserve Additions From All Sources – (f)         677.6   22.5                 2.1            702.2
Production – (g) 282.6   16.1                 2.2            300.9
RESERVE REPLACEMENT COSTS ($ / Boe)      
Total Drilling, Before Revisions – (a / d) $      8.00   $      4.84      $     12.53      $      7.95
All-in Total, Net of Revisions – (b / e) $      9.09   $      3.14      $     10.14      $      8.90
All-in Total, Excluding Revisions Due to Price – (b / (e – c)) $      8.36   $      3.14      $     10.14      $      8.21
RESERVE REPLACEMENT      
Drilling Only – (d / g) 260%   91%               77%            249%
All-in Total, Net of Revisions and Dispositions – (f / g) 240%   140%               95%            233%
All-in Total, Excluding Revisions Due to Price – ((f – c ) / g) 261%   140%               95%            253%
Net Proved Reserve Additions From All Sources – Liquids (MMBbl)      
Revisions (37.6)   0.1                 –                 (37.5)
Purchases in Place 4.9   –                     –                    4.9
Extensions, Discoveries and Other Additions – (h)         537.8               –                    –                537.8
Total Proved Reserve Additions 505.1   0.1                 –                505.2
Sales in Place            (2.2)               –                    –                  (2.2)
Net Proved Reserve Additions From All Sources – (i)         502.9   0.1                 –                503.0
Production – (j) 215.2   0.2                 0.1            215.5
RESERVE REPLACEMENT – LIQUIDS      
Drilling Only – (h / j) 250%   0%                 0%            250%
All-in Total, Net of Revisions & Dispositions – (i / j) 234%   50%                 0%            233%

 

Reconciliation of Drillbit Exploration and Development Expenditures Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) (Unaudited; in millions, except ratio data)

 

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.

 

 

For the Twelve Months Ended December 31, 2019

 

PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)

Total Costs Incurred in Exploration and Development Activities (GAAP)

      Total

 

$ 6,628.2

 

Less:  Asset Retirement Costs                                                                                                                                                (186.1)

Acquisition Costs of Unproved Properties                                                                                                                     (276.1)

Acquisition Cost of Proved Properties                                                                                                                         (379.9)

Drillbit Exploration and Development Expenditures (Non-GAAP) – (k)

  $ 5,786.1

 

Total Proved Reserves – Extensions, Discoveries and Other Additions

(MMBoe)                                                                                                                                                                                 750.0

Add:   Conversion of Proved Undeveloped Reserves to Proved Developed                                                                                302.0

Less:  Proved Undeveloped Extensions and Discoveries                                                                                                         (578.3)

Proved Developed Reserves – Extensions and Discoveries (MMBoe)                                                                                   473.7

Total Proved Reserves – Revisions (MMBoe)                                                                                                                             (60.0)

Less:  Proved Undeveloped Reserves – Revisions                                                                                                                      49.8

Proved Developed – Revisions Due to Price                                                                                                                     59.7

Proved Developed Reserves – Revisions Other Than Price (MMBoe)                                                                                      49.5

 

Proved Developed Reserves – Extensions and discoveries plus Revisions

Other than Price (MMBoe) – (l)                                                                                                                                           523.2

 

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) – (k / l)                              $ 11.06

 

Reconciliation of Total Exploration and Development Expenditures For Drilling Only and Total Exploration and Development Expenditures

Calculation of Reserve Replacement Costs ($ / BOE) (Unaudited; in millions, except ratio data)

 

The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling  Only (Non-GAAP)  and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe.  There are  numerous ways  that industry  participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are  used  by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages  of reported statistics, while others prefer to estimate future costs.  EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

 

  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 – (f)        702.2          665.8          604.4          235.9         (168.0)          597.9
 

Production – (g)

 

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

 

Crude Oil, NGLs and Natural Gas Financial Commodity Derivative Contracts

 

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

 

Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG’s Midland Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

 

                                                                            Midland Differential Basis Swap Contracts

Weighted Average Price

  Volume Differential
         (Bbld)                    ($/Bbl)         
2019    
January 1, 2019 through December 31, 2019 (closed) 20,000 $                1.075

 

 

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG’s  Gulf Coast  Differential basis  swap contracts  through February 19, 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.

 

 

                                                                          Gulf Coast Differential Basis Swap Contracts

Weighted Average Price

  Volume Differential
         (Bbld)                    ($/Bbl)         
2019    
January 1, 2019 through December 31, 2019 (closed) 13,000 $                5.572

 

 

EOG has also entered into crude oil swaps 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 February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

 

 

                                                                                    Roll Differential Swap Contracts

Weighted Average Price

  Volume Differential
         (Bbld)                    ($/Bbl)         
2020    
February 2020 (closed) 10,000 $                  0.70
March 1, 2020 through December 31, 2020 10,000 0.70

 

 

Presented below is a comprehensive summary of EOG’s crude oil price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

 

 

                                                                                    Crude Oil Price Swap Contracts

Weighted

 

 

2019

Volume

         (Bbld)         

Average Price

          ($/Bbl)         

April 2019 (closed) 25,000 $                60.00
May 1, 2019 through December 31, 2019 (closed) 150,000 62.50
2020

January 2020 (closed)

 

200,000

 

$                59.33

February 1, 2020 through March 31, 2020 200,000 59.33
April 1, 2020 through June 30, 2020 200,000 59.59
July 1, 2020 through September 30, 2020 107,000 58.94

 

Presented below is a comprehensive summary of EOG’s Mont Belvieu propane (non-TET) price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

 

                                                                          Mont Belvieu Propane Price Swap Contracts

Weighted

  Volume Average Price
           (Bbld)                    ($/Bbl)         
2020    
January 2020 (closed) 4,000 $                21.34
February 2020 4,000 21.34
March 1, 2020 through December 31, 2020 25,000 17.92

 

 

Presented below is a comprehensive summary of EOG’s natural gas price swap contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

 

 

 

 

 

 

2019

Natural Gas Price Swap Contracts

Weighted

Volume                Average Price

      (MMBtud)                  ($/MMBtu)      

 

April 1, 2019 through October 31, 2019 (closed)                                                                                                 250,000        $                2.90

EOG has also 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. Presented below is a comprehensive summary of EOG’s natural gas collar contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts

    Weighted Average Price ($/MMBtu)

  Volume (MMBtud)        Ceiling Price                Floor Price                            

2020

 

April 1, 2020 through October 31, 2020                                                                             250,000        $

2.50        $

2.00

 

 

 

 

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 February 19, 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.

 

 

                                                                            Rockies Differential Basis Swap Contracts

Weighted Average Price

  Volume Differential
      (MMBtud)              ($/MMBtu)      
2020    
January 1, 2020 through February 29, 2020 (closed) 30,000 $                  0.55
March 1, 2020 through December 31, 2020 30,000 0.55

 

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). Presented below is a comprehensive summary of EOG’s HSC Differential basis swap contracts through February 19, 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.

 

 

                                                                               HSC Differential Basis Swap Contracts

Weighted Average Price

  Volume Differential
        (MMBtud)              ($/MMBtu)      
2020    
January 1, 2020 through February 29, 2020 (closed) 60,000 $                  0.05
March 1, 2020 through December 31, 2020 60,000 0.05

 

 

 

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 February 19, 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.

 

                                                                             Waha Differential Basis Swap Contracts

Weighted Average Price

  Volume Differential
      (MMBtud)              ($/MMBtu)      
2020    
January 1, 2020 through February 29, 2020 (closed) 50,000 $                  1.40
March 1, 2020 through December 31, 2020 50,000 1.40

 

 

 Definitions

Bbld            Barrels per day

$/Bbl           Dollars per barrel

MMBtud      Million British thermal units per day

$/MMBtu     Dollars per million British thermal units NYMEX U.S. New York Mercantile Exchange

 

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

 

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

 

 

Direct ATROR

Based on Cash Flow and Time Value of Money

  • Estimated future commodity prices and operating costs
  • Costs incurred to drill, complete and equip a well, including facilities Excludes Indirect Capital
  • Gathering and Processing and other Midstream
  • Land, Seismic, Geological and Geophysical

 

Payback ~12 Months on 100% Direct ATROR Wells

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

 

 

Return on Equity / Return on Capital Employed

Based on GAAP Accrual Accounting

Includes All Indirect Capital and Growth Capital for Infrastructure

  • Eagle Ford, Bakken, Permian Facilities
  • Gathering and Processing

Includes Legacy Gas Capital and Capital from Mature Wells

 

Reconciliation of After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization

Calculations of Return on Capital Employed and Return on Equity (Unaudited; in millions, except ratio data)

 

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

 

 

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

        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)

Adjustments to Net Income, Net of Tax (See Accompanying

 

$              2,735

 

$          3,419

Schedule)                 158 (1)            (201) (2)
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

 

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

 

              11.8%

 

          15.8%

 

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

 

              12.5%

 

          14.9%

 

Return on Equity (ROE)

   
ROE (GAAP Net Income) – (b) / (e)               13.3%           19.2%
 

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

 

              14.1%

 

          18.1%

 

* Average for the current and immediately preceding year

   
 

Adjustments to Net Income (GAAP)

   

 

 

  • See below schedule for detail of adjustments to Net Income (GAAP) in 2019:

 

                Year Ended December 31, 2019              

  Before Income Tax After
         Tax              Impact           Tax     
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

 

 

  • See below schedule for detail of adjustments to Net Income (GAAP) in 2018:

 

                Year Ended December 31, 2018              

  Before Income Tax After
         Tax              Impact           Tax     
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)

 

Reconciliation of After-Tax Net Interest Expense, Net Debt and Total Capitalization

Calculation of Return on Capital Employed (Unaudited; in millions, except ratio data)

 

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

 

       2017                2016                2015                2014                2013

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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

 

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

 

            13.4%

 

-4.8%

 

-21.6%

 

14.7%

 

12.1%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)  

 

 

            17.1%

 

 

 

-8.1%

 

 

 

-29.5%

 

 

 

17.6%

 

 

 

15.3%

 

 

* Average for the current and immediately preceding year

         

 

       2012                2011                2010                2009                2008

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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 (Loss) (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

 

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

 

             4.0%

 

7.7%

 

1.8%

 

5.4%

 

26.4%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)  

 

 

             4.4%

 

 

 

9.5%

 

 

 

1.6%

 

 

 

5.8%

 

 

 

30.5%

 

 

* Average for the current and immediately preceding year

         

 

       2007                2006                2005                2004                2003

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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 (Loss) (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

 

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

 

            15.7%

 

24.7%

 

30.0%

 

18.2%

 

15.3%

Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)  

 

 

            17.3%

 

 

 

26.2%

 

 

 

34.7%

 

 

 

24.2%

 

 

 

22.1%

 

 

* Average for the current and immediately preceding year

         

 

       2002                2001                2000                1999                1998

Return on Capital Employed (ROCE) (Non-GAAP) (Calculated Using GAAP Net Income)

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 (Loss) (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

 
 

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

 

             4.8%

 

18.2%

 

20.2%

 

27.0%

 
Return on Equity (ROE) (GAAP) ROE (GAAP Net Income) – (b) / (e)  

 

 

             5.2%

 

 

 

26.4%

 

 

 

31.6%

 

 

 

47.2%

 
 

 

* Average for the current and immediately preceding year

         

 

Cash Operating Expenses per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)

 

 

Year Ended December 31,

        2019              2018              2017               2016               2015               2014      
Cash Operating Expenses (GAAP)*            
Lease and Well $ 1,366,993 $ 1,282,678 $ 1,044,847 $      927,452 $ 1,182,282 $ 1,416,413
Transportation Costs 758,300 746,876 740,352 764,106 849,319 972,176
General and Administrative           489,397         426,969           434,467          394,815          366,594          402,010
Cash Operating Expenses 2,614,690 2,456,523 2,219,666 2,086,373 2,398,195 2,790,599
Less: Legal Settlement – Early Leasehold Termination (10,202) (19,355)
Less: Voluntary Retirement Expense (42,054)
Less: Acquisition Costs – Yates Transaction (5,100)
Less: Joint Venture Transaction Costs (3,056)
Less: Joint Interest Billings Deemed Uncollectible                     –                   –             (4,528)                    –                    –                    –
Adjusted Cash Operating Expenses (Non-GAAP) – (a)   $ 2,614,690   $ 2,456,523   $ 2,201,880   $ 2,039,219   $ 2,378,840   $ 2,790,599
Volume – Thousand Barrels of Oil Equivalent – (b) 298,565 262,516 222,251 204,929 208,862 217,073

 

Adjusted Cash Operating Expenses Per Boe (Non-GAAP) – (a) / (b)        $            8.76  (c)  $         9.36  (d)  $           9.91  (e)  $          9.95  (f)   $        11.39  (g)  $                                                                                                 12.86 (h)

 

Adjusted Cash Operating Expenses Per Boe (Non-GAAP) – Percentage Decrease

2019 compared to 2018 – [(c) – (d)] / (d)                                                                -6%

2019 compared to 2017 – [(c) – (e)] / (e)                                                              -12%

2019 compared to 2016 – [(c) – (f)] / (f)                                                                -12%

2019 compared to 2015 – [(c) – (g)] / (g)                                                              -23%

2019 compared to 2014 – [(c) – (h)] / (h)                                                              -32%

 

 

* Includes stock compensation expense and other non-cash items.

 

Cost per Barrel of Oil Equivalent (Boe) (Unaudited; in thousands, except per Boe amounts)

 

 

Three Months Ended

  March 31,

          2019        

June 30,

          2019        

September 30,

          2019        

December 31,

           2019         

Volume – Thousand Barrels of Oil Equivalent – (a) 69,623 73,964 76,748 78,231
Crude Oil and Condensate $     2,200,403 $     2,528,866 $     2,418,989 $      2,464,274
Natural Gas Liquids 218,638 186,374 164,736 215,070
Natural Gas             334,972             269,892             269,625              309,606
Total Wellhead Revenues – (b) $     2,754,013 $     2,985,132 $     2,853,350 $      2,988,950
Operating Costs

Lease and Well

 

$        336,291

 

$        347,281

 

$        348,883

 

$         334,538

Transportation Costs 176,522 174,101 199,365 208,312
Gathering and Processing Costs 111,295 112,643 127,549 127,615
General and Administrative 106,672 121,780 135,758 125,187
Taxes Other Than Income 192,906 204,414 203,098 199,746
Interest Expense, Net               54,906               49,908               39,620                40,695

 

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

$        978,592

$     1,010,127

$     1,054,273

$      1,036,093

 

 

Depreciation, Depletion and Amortization (DD&A)             879,595             957,304             953,597              959,208
Total Operating Cost (excluding Total Exploration Costs) – (d) $     1,858,187 $     1,967,431 $     2,007,870 $      1,995,301
Exploration Costs $          36,324 $          32,522 $          34,540 $           36,495
Dry Hole Costs 94 3,769 24,138
Impairments               72,356             112,130             105,275              228,135
Total Exploration Costs 108,774 148,421 163,953 264,630
Less: Impairments (Non-GAAP)              (23,745)              (65,289)              (27,215)             (158,725)
Total Exploration Costs (Non-GAAP)   $          85,029   $          83,132   $        136,738   $         105,905
 

Total Operating Cost (Non-GAAP) (including Total

       
Exploration Costs) – (e)   $     1,943,216     $     2,050,563     $     2,144,608     $      2,101,206
 

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

 

  $            39.56

   

  $            40.36

   

  $            37.18

   

  $             38.21

Total Cash Operating Cost per Boe (excluding DD&A              
and Total Exploration Costs) – (c) / (a)   $            14.06     $            13.65     $            13.75     $             13.24

 

 

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

  $            25.50

  $            26.71

  $            23.43

  $             24.97

 

 

 

 

 

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

  $            26.69

  $            26.59

  $            26.18

  $             25.50

 

 

 

 

 

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

  $            12.87

  $            13.77

  $            11.00

  $             12.71

 

 

 

 

 

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

  $            27.91

  $            27.72

  $            27.97

  $             26.85

 

 

 

 

 

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

  $            11.65

  $            12.64

  $              9.21

  $             11.36

 

 

 

 

 

Year Ended

                                 December 31,                                

            2019                    2018                   2017        
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)

Total Operating Cost (Non-GAAP) (excluding Total

         3,749,704          3,435,408          3,409,387
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: 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
 

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

 

 

 

 

 

Year Ended

                                 December 31,                                

            2016                    2015                   2014        
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)

Total Operating Cost (Non-GAAP) (excluding Total

         3,553,417          3,313,644          3,997,041
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: 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
 

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

 

 

 

 

EOG RESOURCES, INC.

First Quarter and Full Year 2020 Forecast and Benchmark Commodity Pricing

 

  • First Quarter and Full Year 2020 Forecast

 

The forecast items for the first 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.

 

 

  • 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 Exchanges.

 

  • Benchmark Commodity Pricing

 

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

 

 

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

 

Estimated Ranges (Unaudited)

1Q 2020                                             Full Year 2020

 

Daily Sales Volumes

Crude Oil and Condensate Volumes (MBbld)

United States 479.0 –            487.0 499.0 –               517.6
Trinidad 0.5 –                0.7 1.0 –                   1.2
Other International 0.0 –                0.2 0.0 –                   0.2
Total 479.5 –            487.9 500.0 –               519.0

 

Natural Gas Liquids Volumes (MBbld)

Total                                                                                              150.0     –            160.0                            157.0     –                                                                                                       177.0

 

Natural Gas Volumes (MMcfd)

United States 1,090 –            1,150 1,135 –               1,235
Trinidad 185 –               215 215 –                  255
Other International 25 –                 35 25 –                    35
Total 1,300 –            1,400 1,375 –               1,525

 

Crude Oil Equivalent Volumes (MBoed)

United States 810.7 –            838.7 845.2 –               900.4
Trinidad 31.3 –              36.5 36.8 –                 43.7
Other International 4.2 –                6.0 4.2 –                   6.0
Total 846.2 –            881.2 886.2 –               950.1

 

 

Capital Expenditures ($MM)                                                               $        1,850    –    $       2,050                $          6,300    –  $                                                                                                            6,700

 

Estimated Ranges (Unaudited)

1Q 2020                                                Full Year 2020

Operating Costs  
Unit Costs ($/Boe)

Lease and Well

 

$          4.30

 

–    $         4.80

 

$            4.20

 

–  $              4.80

Transportation Costs $          2.40 –    $         2.80 $            2.30 –  $              2.70
General and Administrative $          1.55 –    $         1.65 $            1.55 –  $              1.65
Gathering and Processing $          1.70 –    $         1.80 $            1.60 –  $              1.80
Depreciation, Depletion and Amortization $        13.00 –    $       13.50 $          12.15 –  $            13.15
 

Expenses ($MM)

       
Exploration and Dry Hole $             40 –    $            50 $             145 –  $               185
Impairment $             80 –    $            90 $             325 –  $               365
Capitalized Interest $               9 –    $            11 $               37 –  $                 43
Net Interest $             39 –    $            41 $             136 –  $               140
Taxes Other Than Income (% of Wellhead Revenue) 7.0% –               8.0% 7.0% –                  8.0%
Income Taxes Effective Rate  

21%

 

–                26%

 

21%

 

–                   26%

Current Tax (Benefit) / Expense ($MM) $            (15) –    $            30 $                 5 –  $                 50

 

Pricing – (Refer to Benchmark Commodity Pricing in text) Crude Oil and Condensate ($/Bbl)

Differentials

United States – above (below) WTI $         (0.10) –  $          0.90 $           (0.50) –  $              1.50
Trinidad – above (below) WTI $       (11.00) –  $         (9.00) $         (11.50) –  $             (9.50)
Other International – above (below) WTI $          0.75 –  $          4.75 $           (0.65) –  $              1.35

 

Natural Gas Liquids

Realizations as % of WTI                                                                      21%  –                27%                              21%  –                                                                                                               27%

 

Natural Gas ($/Mcf) Differentials

United States – above (below) NYMEX Henry Hub             $        (0.70)  –  $         (0.30)              $           (0.90)  –  $                                                                                             (0.30)

 

Realizations  
Trinidad $          2.40 –  $          2.80 $            2.50 –  $              3.20
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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