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DeGolyer and MacNaughton releases TWENTY-FIRST CENTURY PETROLEUM STATISTICS – 74th Edition

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DeGolyer and MacNaughton releases TWENTY-FIRST CENTURY PETROLEUM STATISTICS – 74th Edition

August 12, 2020

DeGolyer and MacNaughton has released their 74th edition of the Twenty-First Century Petroleum Statistics on its website. The data and information contained in this document was initially prepared in 1945 by the office of the Director of Naval Petroleum and Oil Shale Reserves, Navy Department, Washington, D.C. The Director, Commodore W.G. Greenman, requested that DeGolyer and MacNaughton exclusively maintain the ‘handbook’ on an annual basis, since demand indicated that there was a practical need for such information. DeGolyer and MacNaughton have been publishing this ever since as a ready reference for industry colleagues, clients, researchers, libraries, and students.

Please register to access and download the TWENTY-FIRST CENTURY PETROLEUM STATISTICS information:

https://www.demac.com/reference-materials/twenty-first-century-petroleum-statistics/



A Message from DeGolyer and MacNaughton

June 11, 2020

We hope that you and your families are all healthy and staying safe. This letter has been written to update you on the effect that the coronavirus (COVID-19) has had on D&M and its services. While COVID-19 required significant adjustments, thanks to the resourcefulness of our IT department and the continued hard work of our employees, we are proud to report that we have successfully met all the challenges that COVID-19 has presented. Additionally, we have developed many innovative skills, tools, and solutions through this process that will continue to improve our productivity and our ability to assist clients.

Today, June 11, 2020, marks 90 days from our transition from a traditional office environment to a complete work-from-home model. Not only did we navigate this transition without any negative impact to communications or deliverables, we continued to successfully meet client deadlines throughout the pandemic. Locally mandated “Stay at Home” and “Shelter in Place” orders were lifted in mid-May for our Dallas and Houston offices; however, in the interest of employee safety, staff in these offices were allowed to continue working from home. Beginning June 1, Dallas and Houston employees began returning to the office in alternating two-week shifts to allow for proper sanitary and social distancing measures. Plans for reopening our Moscow office are currently in discussion.

All of our offices are observing safety precautions in compliance with the guidelines recommended by local and state governments and by the CDC. Additionally, we have established internal procedures and protocols to further ensure the health of our employees. Throughout this crisis, our top priority has always been to continue providing exceptional services to our clients while maintaining the health and safety of our employees. The entire firm is working hard to ensure that these goals are met, whether from the office or from home.

D&M is strong, and we will continue to serve our clients with knowledge, integrity, and service, as we have since our doors first opened in 1936. As we all navigate through the months ahead, please continue to keep yourself and your families healthy and safe.



A Message from DeGolyer and MacNaughton

March 26, 2020

We hope you and your families are all healthy and safe. This letter is written to address any concerns you may have regarding the coronavirus (COVID-19) and its impact on D&M and its services. We have been paying close attention to the spread of COVID-19 and its potential effects on D&M’s business, employees and clients. A team has been meeting regularly to prepare and implement a plan for D&M should the outbreak continue to spread. We want to assure you that, because of this planning, we are confident that D&M is well equipped to handle any circumstances that may lie ahead. We would like to share with you the preparations and adjustments we have made.

D&M’s top priority is providing exceptional services to our clients while maintaining the health and safety of our employees. Knowing that D&M’s employees and their expertise are our greatest assets, at the beginning of March, we implemented the plan for all of our professional and support staff to work from home. The plan was initiated well before “Stay at Home” or “Shelter-in-Place” orders were issued by local governments. Through this plan, we were able to quickly equip every employee with the necessary tools to work safely from their home while continuing to provide uninterrupted service to our clients during these challenging times.

Additionally, new communication technology has been initiated company-wide. This technology has not only improved remote collaboration, but also ensures that client data and information always remain confidential. The capabilities of D&M’s plans and adjustments have been successfully tested and used by all D&M employees worldwide for the last two weeks. Daily project meetings, both internal and with clients, have continued, and all projects are moving ahead on schedule. Moreover, all projects are expected to finish as scheduled with no delays.  The entire firm is working hard to ensure that we continue to deliver excellent service to our clients through this crisis.

D&M has faced many challenges since our founding in 1936, including a world war, but we have never once closed our doors. Now, thanks to the forethought and planning of D&M and its employees, our doors will remain “virtually” open during this global crisis as well. D&M is strong, and we will continue to serve our clients with knowledge, integrity and service as we always have. Please keep yourself and your families healthy and safe.



Resources at Israel’s Karish North field higher than expected

April 13, 2020

Greece’s Energean Oil and Gas, the oil and gas producer focused on the Mediterranean, announced on April 9 that recoverable resources in Israel’s Karish North field are 32% higher than expected.

According to Energean, an independent Competent Persons Report (CPR) by DeGolyer and MacNaughton (D&M) on the Karish North Field, offshore Israel, and submission of an addendum to the Field Development Plan (FDP) to the State of Israel’s Ministry of Energy for Karish North, certified Karish North to contain gross 2C resources of 33.7 billion cubic metres of gas and 39 million barrels of liquids. This represents a total of 250 million barrels of oil equivalent, of which 84% is gas.

The report delivers a 32% uplift to Energean’s previous Karish North resource best estimate,

including approximately 9 billion cubic metres of gas plus 5 million barrels of liquids of liquids, a total of approximately 60 million barrels of oil equivalent (of which 90% is gas).

“I am delighted that 2C resources at Karish North are some 32% ahead of where we had initially expected,” Energean CEO Mathios Rigas said. “This has enabled us not only to convert 0.6 bcm/yr of contingent contracts into firm, but also to continue targeting additional gas sales opportunities that will be incremental to the 5.6 billion cubic metres of firm gas sales that we now expect to deliver on plateau. We are very pleased to be developing a world-class gas resource of 700 million barrels of oil equivelent and look forward to more gas discoveries in our acreage in Israel and the wider Eastern Med region,” Rigas added.

Total gross 2P + 2C across the Karish, Tanin and Karish North is now estimated to be

almost 99 billion cubic metres of gas plus 82 million barrels of liquids, a total of 698 million barrels of oil equivalent (88% of which is gas), the report read.

According to the report 0.6 billion cubic metres per year contingent Gas Sales and Purchase Agreements (GSPAs) will now be converted to firm; firm GSPAs will now deliver approximately 5.6 billion cubic metres of gas sales on plateau, with FPSO capacity of 8 billion cubic metres per year.

Energean continues to actively market additional gas volumes to secure additional longterm cash flows that are largely insulated from global commodity price fluctuations, the report said, adding that Energean has also submitted an addendum to the Karish and Tanin FDP, to cover the Karish North development, envisaging a production capacity of up to 300 mmscf/d

(approximately 3 billion cubic metres), initially from one well.

Karish North Final Investment Decision (FID) is expected during the second half of 2020 with first gas in 2022.

https://www.neweurope.eu/article/resources-at-israels-karish-north-field-higher-than-expected/



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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  • More News


    • Frontera Reports 10% Growth in Value of Proved Plus Probable (2P) Reserves to $2.1 Billion (C$27.95/Share), NPV10 After Tax

      Frontera - February 19, 2020

    • GeoPark Announces Record 2019 Certified 2P Reserves of 197 mmboe Valued at NPV10 of $2.8 Billion

      GeoPark Limited - February 19, 2020

      • GeoPark Limited , a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Peru, Argentina, Brazil, Chile and Ecuador, today announced its independent oil and gas reserves assessment, certified by DeGolyer and MacNaughton (D&M), under PRMS methodology, as of December 31, 2019.

        D&M’s assessment as of December 31, 2019 does not include reserves or any other information related to the recent acquisition of Amerisur Resources Plc (“Amerisur”) that closed in January 2020. All reserves included in this release refer to GeoPark working interest reserves before royalties paid in kind. All figures are expressed in US Dollars. Definitions of terms are provided in the Glossary on page 11.

        Year-End Certified 2019 D&M Oil and Gas Reserves and Highlights:

        Colombia Reserves Growth

        • PD Reserves: Proven developed (PD) reserves in Colombia increased 17% to 42.4 mmboe, with a PD reserve life index (RLI) of 3.6 years
        • 1P Reserves: Proven (1P) reserves in Colombia increased 15% to 95.9 mmboe, with a 1P RLI of 8.1 years. Net present value after tax discounted at 10% (NPV10) of 1P reserves increased by 15% to $1.6 billion despite using lower price decks.
        • 2P Reserves: Proven and probable (2P) reserves in Colombia increased 10% to 129.0 mmboe (16% adjusting for divested blocks), with a 2P RLI of 10.9 years. NPV10 of 2P reserves increased by 10% to $2.1 billion
        • 3P Reserves: Proven, probable and possible (3P) reserves in Colombia increased 11% to 168.9 mmboe, with a 3P RLI of 14.3 years. NPV10 of 3P reserves increased by 10% to $2.6 billion
        • Reserve Additions and Replacement Ratios: After record production of 11.8 mmboe, the Company added 17.9 mmboe of PD reserves, 24.3 mmboe of 1P reserves, 24.0 mmboe of 2P reserves and 28.1 mmboe of 3P reserves, achieving, respectively, a 152%, 206%, 203% and 238% reserve replacement of PD, 1P, 2P and 3P reserves
        • Finding and Development Costs: Finding and development costs (F&D Costs) for 2019 in Colombia were $2.9 per boe on a 1P basis and $2.6 per boe on a 2P basis

        Consolidated Reserves Growth

        • PD Reserves: PD reserves increased 14% to 52.4 mmboe, with a PD RLI of 3.6 years
        • 1P Reserves: 1P reserves increased 11% to 130.6 mmboe, with 1P RLI of 8.9 years. NPV10 of 1P reserves increased by 11% to $2.0 billion
        • 2P Reserves: 2P reserves increased 4% to 197.3 mmboe (7% adjusting for divested blocks), with a 2P RLI of 13.5. NPV10 of 2P reserves increased by 3% to $2.8 billion
        • Reserve Additions and Replacement Ratios: After record production of 14.6 mmboe, the Company added 21.2 mmboe of PD reserves, 27.3 mmboe of 1P reserves, and 22.7 mmboe of 2P reserves, achieving, respectively, a 145%, 187% and 155% reserve replacement of PD, 1P, and 2P reserves
        • Finding and Development Costs: F&D Costs for 2019 were $4.3 per boe on a 1P basis and $4.5 per boe on a 2P basis

        Net Present Value and Value Per Share

        • GeoPark’s 2P NPV10 increased by 3% to $2.8 billion from $2.7 billion, despite using lower price decks
        • GeoPark’s net debt-adjusted 2P NPV10 increased by 6% to $42.5 per share ($29.6 per share corresponding to Colombia)

        Recent Amerisur Acquisition (Closed in January 2020)

        • Accretive acquisition of Amerisur, providing reserves, production and cash flow growth and enriching GeoPark’s inventory of short, medium and long-term exploration opportunities
        • Amerisur reserves included 15.0 mmbbl and 21.8 mmbbl of 1P and 2P reserves with an estimated NPV10 of 2P reserves of $0.3 billion (certified by McDaniel & Associates as of end-July 2019)

        James F. Park, Chief Executive Officer of GeoPark, said: “This year-end certification is a good scorecard of the ‘nuts-and-bolts’ of our business and how our team consistently performs and delivers growth in value. Our operations team continues to safely and cleanly produce more oil and gas barrels every year – a record in 2019. Our exploration team continues to find even more oil and gas barrels in the subsurface to replace our increasing production and still grow our overall reserve base – another record year. Plus our continually-improving operational efficiency contributes by making every barrel of our reserves more valuable. And, none of these record 2019 achievements include the exciting new production, reserves and resources now in-house from the Amerisur acquisition and the 1+ million new acres acquired in the Llanos basin – which we will be putting to work in 2020.”

        Net Present Value per Share by Country

        The table below presents GeoPark’s NPV per share, by country, of 2P reserves as of December 31, 2019.

        2019 Net Present Value per Share

        Colombia

        Peru

        Chile

        Argentina

        Brazil

        Total

        2P Reserves (mmboe)

        129.0

        31.4

        24.6

        8.5

        3.8

        197.3

        2P NPV10 2019 ($ mm)

        2,075

        336

        308

        57

        62

        2,839

        Shares Outstanding (mm)

        59.2

        59.2

        59.2

        59.2

        59.2

        59.2

        ($/share)

        35.1

        5.7

        5.2

        1.0

        1.0

        48.0

        The table below illustrates the details of the net debt adjusted 2P NPV10 per share:

        Net Debt Adjusted 2P NPV10 per Share

        2019

        2P NPV10 ($ mm)

        2,839

        Shares Outstanding (mm)

        59.2

        Subtotal ($/share)

        48.0

        Net Debta/Share ($/share)

        -5.5

        Net Debt Adjusted 2P NPV10 /Share ($/share)

        42.5

        a) Net debt adjusted 2P NPV10 per share is shown on a consolidated basis. As of December 31, 2019, net debt is calculated considering unaudited financial debt of $437.4 million, less unaudited $111.2 million of cash and cash equivalents.

        2019 Reserve Life Index and Replacement Ratio

        By Reserves

        Category

        Consolidated

        Colombia

        (RLI: years)

        RLI PD

        3.6

        3.6

        RLI 1P

        8.9

        8.1

        RLI 2P

        13.5

        10.9

        (RRR: %)

        RRR PD

        145%

        152%

        RRR 1P

        187%

        206%

        RRR 2P

        155%

        203%

        2019 Year-End Reserves Summary

        GeoPark engaged D&M to carry out an independent appraisal of reserves as of December 31, 2019, covering 100% of its assets in Colombia, Chile, Brazil, Peru and Argentina. D&M’s certification as of December 31, 2019 does not include information related to the acquisition of Amerisur that closed in January 2020 (for information on Amerisur reserves, please refer to the “Recent Amerisur Acquisition” section below).

        Following oil and gas production of 14.6 mmboe in 2019, D&M certified 2P reserves of 197.3 mmboe (88% oil and 12% gas) as of December 31, 2019. By country, the 2P reserves were: 65% in Colombia, 16% in Peru, 13% in Chile, 4% in Argentina and 2% in Brazil.

        All reserves disclosed in this release correspond to GeoPark working interest reserves before royalties paid in kind. Comparative information as of December 2018 has been modified to reflect this criterion, being previously disclosed as GeoPark working interest reserves after royalties.

        Reserves Summary by Country and Category

        Country

        Reserves

        Category

        December 2019

        (mmboe)

        % Oil

        December 2018

        (mmboe)

        % Change

        Colombia

        PD

        42.4

        99%

        36.3

        17%

        1P

        95.9

        100%

        83.4

        15%

        2P

        129.0

        100%

        116.8

        10%

        3P

        168.9

        100%

        152.6

        10%

        Peru

        PD

        100%

        N/A

        1P

        19.2

        100%

        18.5

        4%

        2P

        31.4

        100%

        30.3

        4%

        3P

        121.4

        100%

        131.2

        -7%

        Chile

        PD

        3.4

        26%

        2.8

        21%

        1P

        7.4

        50%

        7.2

        3%

        2P

        24.6

        38%

        24.7

        0%

        3P

        41.1

        37%

        37.9

        8%

        Argentina

        PD

        3.3

        59%

        3.5

        -6%

        1P

        4.9

        67%

        5.7

        -14%

        2P

        8.5

        52%

        14.2

        -40%

        3P

        14.2

        42%

        28.9

        -51%

        Brazil

        PD

        3.2

        5%

        3.1

        3%

        1P

        3.2

        5%

        3.1

        3%

        2P

        3.8

        13%

        3.2

        19%

        3P

        5.6

        40%

        3.4

        65%

        Total (D&M Certified)

        PD

        52.4

        86%

        45.8

        14%

        1P

        130.6

        93%

        117.8

        11%

        2P

        197.3

        88%

        189.3

        4%

        3P

        351.3

        89%

        354.0

        -1%

        Analysis by Business Segment

        Colombia

        After record production of 11.8 mmbbl in 2019 (an increase of 13% over 2018), GeoPark’s 2P D&M certified reserves increased by 10% to 129.0 mmbbl compared to 2018. Reserve additions of 24.0 mmbbl of 2P reserves resulted from strong reservoir performance and continued successful development, appraisal and exploration drilling in the Llanos 34 block (GeoPark operated, 45% WI), and to a lesser extent in the Llanos 32 block (GeoPark non-operated, 12.5% WI).

        On July 1, 2019, GeoPark completed the divestiture of the La Cuerva and Yamu blocks in Colombia. Adjusting for the sale of these blocks (5.3 mmbbl of 2P reserves as of December 31, 2018), the Company’s 2P reserves increased by 16%, resulting in reserve additions of 29.3 mmbbl of 2P reserves.

        For each barrel of oil extracted in Colombia, GeoPark added 2.1 barrels of 1P reserves, the equivalent of a 1P RRR of 206%. Similarly, for each barrel of oil extracted, GeoPark added 2.0 barrels of 2P reserves, resulting in a 2P RRR of 203%.

        As of December 31, 2019, the Llanos 34 block included approximately 120 future development drilling locations (2P, gross).

        The 1P RLI was 8.1 years, while the 2P RLI was 10.9 years.

        The Llanos 34 block represented 95% of GeoPark Colombia 2P D&M certified reserves. The breakdown of the 2P D&M reserves in Colombia consisted of 100% oil.

        Peru

        GeoPark’s 2P D&M certified reserves in Peru increased to 31.4 mmbbl from 30.3 mmbbl in 2018, following D&M’s updated review of the Situche Central light oil field.

        The Situche Central oil field in the Morona block (GeoPark operated, 75% WI) represented 100% of GeoPark’s Peru D&M certified reserves and consisted of 100% oil.

        Chile

        GeoPark’s 2P D&M certified reserves in Chile remained flat at 24.6 mmboe compared to 24.7 mmboe in 2018, resulting from oil and gas production of 1.1 mmboe, partially offset by enhanced reservoir performance and drilling success in the Fell block (GeoPark operated, 100% WI).

        The 1P RLI was 6.7 years. The 2P RLI was 22.4 years.

        The Fell block represented 99% of GeoPark Chile 2P D&M certified reserves.

        The breakdown of the 2P D&M reserves in Chile consisted of 38% oil and 62% gas.

        Argentina

        GeoPark’s 2P D&M certified reserves in Argentina decreased by 40% to 8.5 mmboe compared to 14.2 mmboe in 2018, reflecting technical revisions, delayed development plans and production of 0.9 mmboe during 2019.

        The 1P RLI was 5.4 years, while the 2P RLI was 9.4 years.

        The Aguada Baguales, El Porvenir and Puesto Touquet blocks (GeoPark operated, 100% WI) represented 100% of GeoPark Argentina 2P D&M certified reserves.

        The breakdown of the 2P D&M reserves in Argentina consisted of 52% oil and 48% gas.

        Brazil

        GeoPark’s 2P D&M certified reserves in Brazil increased by 19% to 3.8 mmboe compared to 3.2 mmboe in 2018, mainly resulting from strong reservoir performance in the Manati gas field (GeoPark non-operated, 10% WI), and to a lesser extent, due to the discovery of the Praia dos Castelhanos oil field in the REC-T-128 block (GeoPark operated, 70% WI), partially offset by production of 0.8 mmboe during 2019.

        The 1P RLI was 4.0 years and the 2P RLI was 4.8 years.

        The Manati field represented 88% of GeoPark Brazil 2P D&M certified reserves.

        The breakdown of the 2P D&M reserves in Brazil consisted of 13% oil and 87% gas.

        D&M Certified Reserves Change by Country

        The following table shows the change in 2P reserves by country from December 31, 2018 to December 31, 2019:

        (mmboe)

        Colombia

        Peru

        Chile

        Argentina

        Brazil

        Total

        2P Reserves as of Dec. 31, 2018

        116.8

        30.3

        24.7

        14.2

        3.2

        189.3

        2019 Production

        -11.8

        0.0

        -1.1

        -0.9

        -0.8

        -14.6

        Net Change

        29.3

        1.1

        1.0

        -4.8

        1.4

        28.0

        Divestitures (*)

        -5.3

        -5.3

        2P Reserves as of Dec. 31, 2019

        129.0

        31.4

        24.6

        8.5

        3.8

        197.3

        (*) Corresponds to the divestiture of the La Cuerva and Yamu blocks in Colombia, that was completed on July 1, 2019.

        Net Present Value Summary

        The table below details D&M certified NPV10 by country and by category of reserves as of December 31, 2019 as compared to 2018:

        Country

        Reserves

        Category

        NPV10 2019

        NPV10 2018

        ($ mm)

        ($ mm)

        Colombia

        1P

        1,574

        1,366

        2P

        2,075

        1,884

        3P

        2,645

        2,394

        Peru

        1P

        222

        264

        2P

        336

        410

        3P

        1,385

        1,896

        Chile

        1P

        121

        94

        2P

        308

        306

        3P

        514

        495

        Argentina

        1P

        40

        44

        2P

        57

        93

        3P

        97

        262

        Brazil

        1P

        51

        49

        2P

        62

        52

        3P

        87

        56

        Total

        1P

        2,008

        1,817

        (D&M Certified)

        2P

        2,839

        2,745

        3P

        4,727

        5,103

        Lower Oil Price Forecast

        Brent oil prices in the 2019 D&M report are lower than the 2018 D&M report. In spite of lower oil prices in the forecast, the NPV10 of 1P and 2P reserves increased in value compared to 2018.

        The price assumptions used to estimate feasibility of PRMS reserves and NPV10 in 2019 and 2018 D&M reports are detailed in the table below:

        Brent Oil Price

        ($/bbl)

        2020

        2021

        2022

        2023

        2024

        2025-

        2027

        2019 Reserves Report

        66.0

        69.0

        71.6

        73.1

        74.6

        76.5-79.8

        2018 Reserves Report

        68.2

        71.0

        73.4

        75.4

        77.4

        79.4-83.2

        After 2027, Brent oil prices in the 2019 D&M report grow by 2% per year.

        Total D&M Certified Future Net Revenue (Actual and Discounted)

        The table below presents D&M’s best estimate of GeoPark’s future net revenue (both actual and discounted at a 10% rate) and the unit value per boe, by country, and by category of certified reserves as of December 31, 2019:

        ($ mm)

        Oil and Gas
        Revenues

        Royalties

        Operating
        Costs

        Future
        Development
        Capital and
        Abandonment
        Costs

        Income
        Tax and
        Other
        Taxes

        Future
        Net
        Revenue
        after tax

        Future Net
        Revenue
        after tax
        discounted
        at 10%

        Unit Value
        after tax
        discounted
        at 10%

        (per boe)

        Colombia1

        1P

        5,237

        249

        628

        277

        1,565

        2,519

        1,574

        $16

        2P

        7,195

        408

        761

        329

        2,219

        3,480

        2,075

        $16

        3P

        9,590

        587

        887

        422

        3,043

        4,651

        2,645

        $16

        Peru

        1P

        1,581

        88

        442

        278

        235

        536

        222

        $12

        2P

        2,678

        153

        700

        404

        431

        990

        336

        $11

        3P

        10,748

        1,167

        1,499

        1,350

        2,039

        4,693

        1,385

        $11

        Chile

        1P

        330

        15

        92

        35

        13

        176

        121

        $16

        2P

        981

        42

        260

        152

        65

        462

        308

        $13

        3P

        1,621

        69

        408

        216

        125

        803

        514

        $13

        Argentina

        1P

        258

        39

        95

        49

        20

        53

        40

        $8

        2P

        402

        60

        111

        106

        39

        85

        57

        $7

        3P

        622

        93

        137

        171

        69

        151

        97

        $7

        Brazil

        1P

        119

        9

        40

        2

        5

        60

        51

        $16

        2P

        153

        13

        44

        7

        14

        75

        62

        $16

        3P

        276

        25

        50

        28

        52

        121

        87

        $16

        Total

        1P

        7,525

        400

        1,297

        642

        1,840

        3,344

        2,008

        $15

        2P

        11,409

        676

        1,876

        998

        2,768

        5,092

        2,839

        $14

        3P

        22,857

        1,941

        2,981

        2,188

        5,328

        10,419

        4,727

        $13

        _____________________________

        1Oil and gas revenues in Colombia are shown net of earn-out expenses, per IFRS rules, of $236 mm (1P), $319 mm (2P) and $419 mm (3P). D&M reported earn-out expenses as operating costs.

        Finding and Development Cost by Reserves Category

        The table below sets forth the calculation of F&D Cost as of December 31, 2019:

        December 31, 2019

        1P

        2P

        Colombia
        1P

        Colombia
        2P

        2019 Capital Expenditure (unaudited) ($ mm)

        126.7

        126.7

        76.8

        76.8

        Reserve Additions by Country (mmboe)

        Colombia

        26.6

        29.3

        26.6

        29.3

        Peru

        0.7

        1.1

        Chile

        1.3

        1.0

        Brazil

        0.9

        1.4

        Argentina

        0.1

        -4.8

        Total Reserve Additions (mmboe)

        29.6

        28.0

        26.6

        29.3

        F&D Cost ($/boe)

        4.3

        4.5

        2.9

        2.6

        F&D Cost is calculated dividing 2019 capital expenditure (unaudited) by reserve additions, as shown in the table above. Reserve additions in Colombia exclude the effect of the divestiture of the La Cuerva and Yamu blocks for 2.3 mmbbl and 5.3 mmbbl of 1P and 2P reserves, respectively, that was completed in July 1, 2019.

        Recent Amerisur Acquisition

        GeoPark announced the closing of the Amerisur acquisition on January 16, 2020. The Amerisur acquisition incorporates 13 production, development and exploration blocks in Colombia, including 12 operated blocks in the Putumayo basin and the non-operated CPO-5 block in the Llanos basin, the Oleoducto Binacional Amerisur (an export oil pipeline from Colombia to Ecuador), and valuable partnerships with Oxy and ONGC (the national oil company of India and operator of the CPO-5 block).

        Amerisur reported reserves, certified by McDaniel & Associates as of end of July 2019, were as follows:

        Reserves Category

        July 2019

        (mmbbl)

        % Oil

        1P

        15.0

        100%

        2P

        21.8

        100%

        3P

        31.1

        100%

        Amerisur’s reported 2P reserves breakdown includes 12.3 mmbbl for the Platanillo block (Operated, 100% WI) and 9.5 mmbbl for the CPO-5 block (Non-operated, 30% WI), where multiple development drilling opportunities have been identified to continue growing production.

        Amerisur is a cashflow-positive, growing business with low operating costs and a strong balance sheet with no debt, and a cash position of $36 million as of September 30, 2019. Additional key metrics of Amerisur include net light oil production of 6,865 bopd (September 2019) and net unrisked exploration resources of 289 to 566 mmbbl (mean to high-end, as estimated by McDaniel & Associates).

        For further details, please refer to the releases published on November 15, 2019 and January 16, 2020.

        OTHER NEWS / RECENT EVENTS

        Reporting Date for 4Q2019 Results Release, Conference Call and Webcast

        GeoPark will report its 4Q2019 and Annual 2019 financial results on Wednesday, March 4, 2020 after the market close.

        In conjunction with 4Q2019 results press release, GeoPark’s management will host a conference call on March 5, 2020 at 10:00 am (Eastern Standard Time) to discuss these 4Q2019 financial results. To listen to the call, participants can access the webcast located in the Investor Support section of the Company’s website at www.geo-park.com.

        Interested parties may participate in the conference call by dialing the numbers provided below:

        United States Participants: 866-547-1509
        International Participants: +1 920-663-6208
        Passcode: 3981263

        Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast.

        An archive of the webcast replay will be made available in the Investor Support section of the Company’s website at www.geo-park.com after the conclusion of the live call.

        GLOSSARY

        1P Proven Reserves

        2P Proven plus Probable Reserves

        3P Proven plus Probable plus Possible Reserves

        boe Barrels of oil equivalent (6,000 cf gas per bbl of oil equivalent)

        boepd Barrels of oil equivalent per day

        bopd Barrels of oil per day

        Certified Reserves Refers to GeoPark working interest reserves before royalties paid in kind, independently evaluated by the petroleum consulting firm, DeGolyer and MacNaughton Corp. (“D&M”)

        F&D Cost Finding and Development Cost, calculated as the unaudited cash flow from investing activities divided by the applicable net reserves additions before changes in Future Development Capital

        mboed Thousands of Barrels of oil equivalent per day

        mmboed Millions of Barrels of oil equivalent per day

        mmbbl Millions of Barrels of oil

        mcfpd Thousands of standard cubic feet per day

        mmcfpd Millions of standard cubic feet per day

        NPV10 Net Present Value after tax discounted at 10% rate

        PD Proven Developed Reserves

        PUD Proven Undeveloped Reserves

        PRMS Petroleum Resources Management System

        RLI Reserve Life Index

        RRR Reserve Replacement Ratio

        sqkm Square kilometers

        WI Working Interest

        NOTICE

        Additional information about GeoPark can be found in the “Investor Support” section of the website at www.geo-park.com

        The reserve estimates provided in this release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. Statements relating to reserves are by their nature forward-looking statements.

        Gas quantities estimated herein are reserves to be produced from the reservoirs, available to be delivered to the gas pipeline after field separation prior to compression. Gas reserves estimated herein includes fuel gas.

        Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in this press release may vary from those obtained by performing the same calculations using the figures in the financial statements. In addition, certain other amounts that appear in this press release may not sum due to rounding.

        Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses.

        All evaluations of future net revenue contained in the D&M Reports are after the deduction of cash royalties, development costs, operating expenses, production and profit taxes, fees, earn out payments, well abandonment costs, and country income taxes from the future gross revenue. It should not be assumed that the estimates of future net revenues presented in the tables represent the fair market value of the reserves. The actual production, revenues, taxes and development, and operating expenditures with respect to the reserves associated with the Company’s properties may vary from the information presented herein, and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the D&M Report will be attained, and variances could be material.

        CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

        This press release contains statements that constitute forward-looking statements. Many of the forward looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe’’, ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

        Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters including 2020 work program, NPV10 and NPV10/share estimations, estimated future revenues, the Amerisur acquisition and oil price forecast. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

        Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see the Company’s filings with the U.S. Securities and Exchange Commission.

        Information about oil and gas reserves: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proven, probable and possible reserves that meet the SEC’s definitions for such terms. GeoPark uses certain terms in this press release, such as “PRMS Reserves” that the SEC’s guidelines do not permit GeoPark from including in filings with the SEC. As a result, the information in the Company’s SEC filings with respect to reserves will differ significantly from the information in this press release. NPV10 for PRMS 1P, 2P and 3P reserves is not a substitute for the standardized measure of discounted future net cash flows for SEC proved reserves.

        Contacts

        INVESTORS:
        Stacy Steimel – Shareholder Value Director ssteimel@geo-park.com
        Santiago, Chile
        T: +562 2242 9600

        Miguel Bello – Market Access Director mbello@geo-park.com
        Santiago, Chile
        T: +562 2242 9600

        MEDIA:
        Jared Levy – Sard Verbinnen & Co jlevy@sardverb.com
        New York, USA
        T: +1 (212) 687-8080

        Kelsey Markovich – Sard Verbinnen & Co kmarkovich@sardverb.com
        New York, USA
        T: +1 (212) 687-8080

        https://www.businesswire.com/news/home/20200210005425/en/GeoPark-Announces-Record-2019-Certified-2P-Reserves

    • NOVATEK’s 2019 organic reserve replacement reached 252%

      Novatek - January 23, 2020

      • NOVATEK today announced that independent petroleum engineers, DeGolyer & MacNaughton, have completed their comprehensive reserve appraisal of the company’s hydrocarbon reserves as of 31 December 2019.

        Total SEC proved reserves, including the company’s proportionate share in joint ventures, aggregated 16,265 million barrels of oil equivalent (boe), including 2,234 billion cubic meters (bcm) of natural gas and 193 million metric tons (mmt) of liquid hydrocarbons. Total proved reserves increased by 3% (excl. 2019 production) as compared to the year-end 2018, representing a reserve replacement rate of 181% for the year, with the addition of 1,065 million boe, incl. of 2019 production.

        The organic reserve replacement rate, excluding the effect from acquisitions and disposals, which mainly related to the disposal of 40% participation interest in Arctic LNG 2 project, amounted to 252%, with the addition of 1,487 million boe, inclusive of 2019 production.

        The company’s reserves were positively impacted by successful exploration at the Geofizicheskoye, Utrenneye and Kharbeyskoye fields, production drilling at the Urengoyskoye, East-Urengoyskoye+North-Esetinskoye (Samburgskiy license area),  East-Tazovskoye, North-Russkoye and South-Tambeyskoye fields, as well as the discovery of the Nyakhartinskoye field and new Achimov deposits in the Gydanskiy license area. The Soletsko-Khanaveyskoye field acquired in 2019 was included into our reserves appraisal. The Company’s reserves appraisal under PRMS standards also includes the new North-Obskoye field discovered in 2018.

        The company significantly increased its exploration activities in 2019 as well as acquired new license areas on the Gydan Peninsula. The inclusion of large geological discoveries in reserves appraised under international reserve standards will contribute significant hydrocarbon resources to successfully implement future NOVATEK’s large-scale LNG projects in the Arctic zone and ensure the maintenance of natural gas production levels into the domestic pipeline network.

        Under the PRMS reserves reporting methodology, the company’s total proved plus probable reserves, including the company’s proportionate share in joint ventures, aggregated 28,725 million boe, including 3,901 bcm of natural gas and 373 mmt of liquid hydrocarbons.

        The organic proved plus probable reserves replacement rate under the PRMS standards, excluding the effect from acquisitions and disposals, which mainly related to the disposal of 40% participation interest in Arctic LNG 2 project, amounted to 200%, with the addition of 1,177 million boe, inclusive of 2019 production.

        To read the news in Russian.

        NOVATEK reserves according to international standards

        Proved reserves under the SEC methodology Proved plus Probable reserves under the PRMS methodology
        2019 2018 2019 2018
        Natural gas, bcm 2,234 2,177 3,901 4,021
        Liquid hydrocarbons, mmt 193 181 373 387
        Total hydrocarbon reserves,
        million boe
        16,265 15,789 28,725 29,619
        Reserves to production (R/P) ratio*

  • 2019


    • Congratulations to Saudi Aramco on their IPO

      Saudi Aramco - December 11, 2019

    • 2020 Vision-How We See Our Greatest Challenges

      November 25, 2019

      • The new decade starts soon, and the users of the TWENTY-FIRST CENTURY PETROLEUM STATISTICSTM are a reflection of the petroleum industry in outlook. The users are from all parts of the business and share an interest in where the exploration, production, and sale of petroleum is headed. In fact, all of you have “2020 vision”!

        As such, we are interested in what you think about the greatest challenges you or your company may face in 2020 and beyond. Simply answer the following questions and we will compile the answers and report back what has been said. This survey is anonymous and your participation will not result in any use of your information other than the compilation of answers in this poll.

        The compiled results will be published on this site early January.

        2020 Vision-How We See Our Greatest Challenges

    • NOC and Zallaf Company discuss development plans for discovered and undeveloped fields with the American firm DeGolyer and MacNaughton

      September 16, 2019

      • National Oil Corporation (NOC) chairman, Eng. Mustafa Sanalla, met with Mr John W. Wallace, chairman and CEO of DeGolyer and MacNaughton, in Tunis. Also present were NOC board member for Exploration and Production, Eng. Abulgasem Shengheer, and Dr Khalifa Rajab Abdul Sadiq, chairman of the Management Committee of Zallaf Oil & Gas Exploration and Production Company.

        NOC chairman and the CEO of DeGolyer and MacNaughton discussed areas of cooperation between NOC, DeGolyer and MacNaughton and Zallaf Company. The three entities will work together in order to prepare technical studies and outline plans to develop discovered and undeveloped fields.

        All parties expressed their desire to enhance their relations by initiating reservoir and field development studies, assessing reserves and preparing development plans for discovered and undeveloped fields. The corporation seeks to put these plans on the production line as soon as possible in order to increase oil and gas production rates and ensure continuous supplies to power plants.

        The meeting also touched upon an extensive study of oil and gas resources and the application of the latest recovery techniques in the basins of Sirte, Ghadames and Murzuq

        https://noc.ly/index.php/en/new-4/5103-noc-and-zallaf-company-discuss-development-plans-for-discovered-and-undeveloped-fields-with-the-american-firm-degolyer-and-macnaughton

    • Ecopetrol and Occidental Form Strategic Partnership to Develop Acreage in Midland Basin

      August 1, 2019

    • Arrow Exploration Corp. Announces Commercial Discovery at Rio Cravo Este

      June 10, 2019

      • ARROW Exploration Corp. (“Arrow” or the “Company”) (TSXV: AXL) is pleased to announce test results of the Rio Cravo Este-1 (“RCE-1”) exploration well located on the Tapir Block in the Llanos Basin of Colombia. RCE-1 was spud on April 25, 2019 and reached a total depth of 10,000 feet measured depth (“ft md”) within the Ubaque Formation. As announced on May 15th, the well encountered 103 feet of net oil pay (true vertical depth) with most of the pay indicated on logs within the C7, Gacheta, and Ubaque formations.  The RCE-1 exploration well was perforated and tested over a 12-foot interval (true vertical depth) in the ‘C7 A’ Sand. An 11-day clean-up and production test period commenced May 30 at 09:00 hours and was concluded June 9 at 08:00 hours. Oil production over the test period averaged 613 barrels per day (“bbl/d”) of 28.3 API oil at a 46.5% water cut over a range of choke sizes.  A peak oil rate of 1,172 bbl/d was recorded and the well did not produce any natural gas during the production test.

        Jack Scott, Chief Operating Officer, stated, “We’re very pleased with our RCE-1 test results. Arrow has now gone two for two on exploration wells since forming the company with our success on Danes-1 late last year and current success on RCE-1. RCE-1 was an earn-in commitment well with an accelerated payback provision which means we’re able to recover $3 million of the cost of the well from 50% of our partner’s working interest barrels. Next steps include carrying out a pressure build-up test and putting the well on continuous production from the C7 Sand.”

        Tapir Block Forward Plans

        After the drilling and completion of RCE-1, Arrow has fulfilled its commitment to earn a 50% working interest in the Tapir Block, which has no further work commitments or land expiries for 20 years. However, given the amount of net pay encountered in RCE-1 and the mapped extent of the accumulation, testing the Gacheta and Ubaque formations in the RCE-1 well and drilling up to two development locations and a water disposal well are currently being evaluated. The water disposal well and one development drilling location are currently licensed. In addition, multiple leads and fault trends have been identified on the Tapir Block with existing 2D seismic data. These leads and trends will be more clearly defined with the completion of an extensive new 3D seismic survey which Arrow plans to acquire over the next 12 months.

        The Company is currently sharing the RCE-1 test results with its reserve evaluator (DeGolyer & MacNaughton of Dallas, TX) for the purpose of procuring an updated reserve report which is anticipated to be completed prior to October 1, 2019. Arrow does not currently have any reserves booked on the Tapir Block, therefore, any reserves which may be ascribed to the RCE-1 discovery would represent incremental upside to Arrow’s corporate reserves.

        Bruce McDonald, President & CEO, commented, “We remain focused on our business plan to add production, reduce commitments and protect downside for our shareholders. We’ve now grown corporate production by approximately 100% per share net of dispositions with our success at RCE-1 without compromising our balance sheet. We continue to work diligently towards closing a credit facility and we look forward to updating the market on this item in the near-term. The combination of our recent Brent crude oil hedge and the expected incremental cash flow from RCE-1 puts Arrow in an excellent position to continue our production growth for the balance of this year and into next.”

        About ARROW Exploration

        Arrow Exploration Corp. (operating in Colombia via its 100% owned subsidiary Carrao Energy S.A.) is a publicly-traded company with a portfolio of premier Colombian oil assets that are underexploited, underexplored and offer high potential growth. The Company’s business plan is to rapidly expand oil production from some of Colombia’s most active basins, including the Llanos, Middle Magdalena Valley (MMV) and Caguan/ Putumayo Basin. The asset base is operated with high working interests, and the Brent-linked light oil pricing exposure combines with low royalties to yield attractive potential operating margins. Arrow’s seasoned team is led by a hands-on and in-country executive team supported by an experienced board.  Arrow is listed on the TSX Venture Exchange under the symbol “AXL”.

        Reader Advisory

        Neither the TSX Venture Exchange (TSXV) nor its regulation services provider (as that term is defined in the policies of the TSXV) accepts responsibility for the adequacy or accuracy of this release.

        This press release contains certain forward-looking statements within the meaning of applicable securities laws. Forward-looking statements are frequently characterized by words such as “plan”, “expect”, “project”, “target”, “intend”, “believe”, “anticipate”, “estimate” and other similar words, or statements that certain events or conditions “may”, “should” or “will” occur. In particular, this news release contains forward-looking statements and information related to drilling and testing results at RCE-1 and the Company’s analysis of well logs and other technical data, as well as statements related to anticipated production from and cash flows related to the RCE-1 well and associated timelines as well as procurement of both an additional seismic survey and an updated reserves report. Although Arrow believes that expectations and assumptions on which the forward-looking statements and information are based are reasonable, undue reliance should not be placed on the forward-looking information and statements because Arrow cannot give any assurances that they will prove to be correct.  Forward-looking statements are based on the opinions and estimates of management at the date the statements are made and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements, including but not limited to future development at Rio Cravo Este, expectations and assumptions concerning Arrow’s ability to develop the assets and obtain the benefits thereof, the ability to efficiently integrate the assets, results of operations, performance, delays or changes in plans with respect to exploration and development or capital expenditure, failure to obtain necessary regulatory approvals for planned operations, and health, safety and environmental risks. Arrow cautions that the foregoing list of risks and uncertainties is not exhaustive. The Company cannot assure that actual results will be consistent with these forward-looking statements. They are made as of the date hereof and are subject to change and the Company assumes no obligation to revise or update them to reflect new circumstances, except as required by law.

        SOURCE ARROW Exploration Corp.

        https://www.newswire.ca/news-releases/arrow-exploration-corp-announces-commercial-discovery-at-rio-cravo-este-851975449.html

    • D&M CEO, John Wallace, at SPIEF Energy Panel

      June 6, 2019

      • The Energy Panel is a premier discussion platform for oil and gas leaders, government officials and acclaimed industry experts. In 2015, UN member states unanimously supported the Resolution Transforming our World: the 2030 Agenda for Sustainable Development. This agenda is a plan of action for improving the well-being of people, securing the planet and prosperity. Oil and gas will remain the backbone of the global energy mix. Advancement of the oil and gas industry is a prerequisite for eradicating poverty and hunger, bridging the inequality gap and ensuring decent living standards, which is essential for sustainable development. The Energy Panel Session will provide a comprehensive insight into sustainable energy development, underlining the industry’s multinational and multicultural nature, and its geographical diversity. The discussion participants will exchange views on energy market trends, transformation of the oil and gas industry, and dynamics of the geopolitical impacts on the markets, as well as offering opinion on the cooperation and innovation potential, ensuring an effective transition to the low carbon economy.

        View the panel presentation at this link. (You can view in English or Russian by clicking the headphone icon within the video.)

        https://www.forumspb.com/en/programme/68864/?ELEMENT_ID=68864

        Moderators
        Evgeny Primakov, Member of the State Duma of the Federal Assembly of the Russian Federation; Journalist; Author of the International Review Programme, Russia-24 TV Channel; Chairman of the Supervisory Board, Russian Humanitarian Mission
        Nobuo Tanaka, Chairman, Sasakawa Peace Foundation; Executive Director (2007–2011), International Energy Agency

        Key note
        Igor Sechin, Chief Executive Officer, Chairman of the Management Board, Deputy Chairman of the Board of Directors, Rosneft

        Panellists
        H.E. Ali Shareef Al-Emadi, Minister of Finance of Qatar
        Ivan Glasenberg, Chief Executive Officer, Glencore
        Robert Dudley, Group Chief Executive, BP
        Neil Duffin, President, ExxonMobil Global Projects Company
        Lorenzo Simonelli, Chairman of the Board of Directors, President, Chief Executive Officer, Baker Hughes, a GE Company
        John W. Wallace, Chairman and CEO, DeGolyer & MacNaughton

    • The Saudi Plan To Boost Spare Oil Production Capacity

      May 9, 2019

      • Even as Saudi Arabia’s oil production reached record levels, with total output hitting 11.1m barrels per day (bpd) in November 2018, the country is boosting levels of investment to ensure there is spare capacity to meet a global supply shock and subsequent increase in prices. According to Khalid Al Falih, the minister of energy, industry and mineral resources, the country will invest $20bn to pump another 1m bpd of crude in order to maintain spare capacity.

        EMERGENCY SUPPLY: The US Energy Information Administration defines spare capacity as the volume of production that can be brought online within 30 days and maintained for 90 days. Typically, lower capacity can trigger an increase in oil prices. In recent years Saudi Arabia has had the world’s largest spare capacity, of between 1.5m and 2m bpd. In October 2018 that buffer slimmed to 1.3m bpd as the country began pumping 10.7m bpd, as it has a maximum output capacity of 12m bpd. The buffer fell further to 900,000 bpd when output increased in November.

        FIELD IMPROVEMENTS: Saudi Aramco was able to reach record output levels in November 2018 due to its increased capacity as one of its fields came onstream and a bottleneck in another field was repaired. The company’s 2017 annual report noted it was on course to boost output from its Khurais oil field by 300,000 bpd in 2018 to give the field a total daily output capacity of 1.5m bpd. Khurais, which produces Arabian light crude oil, was first discovered in 1957.

        The latest boost in capacity is the result of an improvement programme launched in 2012, which developed the Lower Fadhli field and built new processing facilities to handle 300,000 bpd of crude, 143m standard cu feet per day (scfd) of associated gas and 34,000 bpd of natural gas liquids (NGLs). As part of this programme, approximately 650 km of pipeline was constructed to transport crude oil, gas, NGLs and seawater.

        As the additional supply from Khurais entered the market in late 2018, a technical issue at the offshore Manifa field, which has the capacity to produce 900,000 bpd of heavy crude oil, was solved. The field, which is comprised of 27 drilling islands linked by a 42km causeway, was reportedly hit by a technical issue in 2017. Reuters reported that corrosion of the water injection system used to maintain pressure in the reservoir was reducing output and that costly repairs would potentially require a shutdown period. It was reported that the repairs resulted in a combined increase in production of 550,000 bpd from Khurais and Manifa in the fourth quarter of 2018.

        In Saudi Aramco’s 2017 annual report the company noted it made two new oil field discoveries in 2017 at Sakab and Zumul. However, the report did not give an indication of the capacity of the two fields or of how long the development of the new sites could potentially take. In his message in the annual report, Al Falih said that the oil industry globally had lost $1trn in planned investments since the 2014 fall in oil prices, despite the growth in global demand, which rose by 1m bpd to 1.5m bpd, as well as the declining returns from some of the world’s more mature oil fields. “Significant new investments are required in additional capacity and expanded and upgraded infrastructure, as well as the development of pioneering technology to make petroleum energy more sustainable and accessible,” he wrote. “Saudi Aramco is committed to playing its unique part in meeting the world’s energy needs today and tomorrow by continuing to invest wisely throughout the cycle and across the value chain.”

        NEUTRAL ZONE: If a diplomatic bottleneck can be eased, Saudi Arabia can also tap its halfshare in an additional 500,000 bpd of production in the neutral zone it shares with Kuwait. The offshore Khafji field was shut down in October 2014 and the onshore Wafra field ceased production in May 2015. Khafji is owned by Saudi Aramco Gulf Operations Company and Kuwait Gulf Oil Company (KGOC), while Wafra is operated by KGOC and Saudi Arabian Chevron.

        The shutdowns were caused by disputes over flaring regulations and Kuwait’s objection to having an international oil company operating in the zone. Talks between the two countries over the operation of the fields began in the summer of 2018; however, these appeared to stall in October after a meeting between Saudi Crown Prince Mohammed bin Salman bin Abdulaziz Al Saud and Sheikh Sabah Al Jaber Al Sabah, the emir of Kuwait, failed to reach an agreement. S&P Global Platts reported that many observers believed the dispute would only be solved through international arbitration unless a sudden drop in the level global oil supply prompted the two sides to return to negotiations.

        AUDIT REPORT: Saudi Arabia’s ability to meet spare capacity needs was given a boost in January 2019 with the publication of an independent auditor’s report on Saudi Aramco’s proven reserves of oil and gas, which increased the estimated total by over 2bn barrels. The audit, conducted by Texas consulting firm DeGolyer and MacNaughton (D&M), was commissioned as part of Saudi Aramco’s preparations for an initial public offering that is now slated to take place in 2021. The audit found the company had proven reserves of 263.1bn barrels of oil, 2.2bn barrels more than the estimates of the 2017 annual report. It also put total reserves of natural gas at 319.5trn cu feet, compared to the figure of 302.3trn cu feet that was previously reported. When the neutral zone total was included, D&M estimated oil reserves of 268.5bn barrels, compared to an earlier figure of 266.3bn barrels.

        In a statement Al Falih welcomed the findings and said they underscored three important aspects of the country’s hydrocarbons sector: that world-leading economies of scale make the fields the lowest cost globally; the carbon intensity of Saudi Arabia’s oil is among the lowest in the world; and the findings underline the accuracy of the country’s reporting. “This certification underscores why every barrel we produce is the most profitable in the world,” he said. D&M’s assessment was based on 54 reservoirs that make up 80% of Saudi Aramco’s reserves. These reservoirs were found to contain around 213.1bn barrels compared to Saudi Aramco’s own estimate of 210.9bn barrels. The audit was limited to booked oil and gas reserves and did not include more recent discoveries including unconventional gas deposits.

        CRUDE BURNING: The volumes of crude oil Saudi Arabia has available to export abroad are also affected by levels of domestic consumption. Historically, the country’s power stations have burned crude oil in the summer months as an extra feedstock to meet peak demand for air conditioning. However, a key part of upstream strategy is the development of natural gas fields that can provide a replacement source of feedstock for those power plants and industrial users. Data from the Joint Organisations Data Initiative (JODI) shows Saudi consumption of crude oil in power generation fell in recent years as the new gas came onstream. At its summer peak, the use of oil can typically rise by 600,000 bpd, but JODI figures show it fell to 430,000 bpd by 2017. Jodi data also showed that stockpiles of Saudi crude fell by 95m barrels, or 29%, from October 2015 to April 2018 as production decreases from the Organisation of Petroleum Exporting Countries (OPEC) were implemented. This suggests that as Saudi Arabia complies with new OPEC production cuts from January 2019 there will be ample storage to hold spare capacity.

        Developing a deeper oil and gas spare capacity is a priority of Saudi officials to protect the sector and the economy as a whole from potential supply shocks and subsequent price instability, especially as in 2018 the energy sector contributed an estimated 34% of the country’s GDP. Substantial investment in spare capacity and reports that the country’s oil and gas reserves are larger than previously estimated support these efforts and put Saudi Arabia’s energy sector in a position of strength should a future supply shock arise.

        By Oxford Business Group

        https://oilprice.com/Energy/Crude-Oil/The-Saudi-Plan-To-Boost-Spare-Oil-Production-Capacity.html

    • NOC Chairman discusses cooperation with Caterpillar and DeGolyer & MacNaughton

      May 7, 2019

      • National Oil Corporation (NOC) chairman, Eng. Mustafa Sanalla, held a series of meetings yesterday in the US city of Houston as part of NOC’s 60-billion USD procurement drive. The NOC chairman is meeting with US counterparts to discuss the technology and expertise needed to achieve the corporation’s stated production target of 2.1 million barrels per day by 2023.
        Sanalla met with Caterpillar’s EMEA director, Mr Mikhail Potekhin, to review the company’s activities in Libya, including a 150-million USD contract for its subsidiary Solar Turbines for power generation equipment, in addition to future potential cooperation and projects with NOC operating companies.
        The NOC chairman also met with Mr John Wallace, CEO and chairman of DeGolyer and MacNaughton, a global petroleum consulting company, to discuss possible cooperation and study of Libyan field reservoirs, field development, reserve evaluation, and overall technical assistance to NOC subsidiaries.
        The NOC delegation included Dr Khalifa Rajab, chairman of the Zalaf Management Committee, Mr Osama Mohammed Al Lotti, Akakus Management Committee member for Engineering and Projects, and Mr Mohamed Abdo Denbarno, general manager of NOC’s Houston office.
        Caterpillar’s EMEA director was accompanied by Mr Shane Singarayer, Oil & Gas director for Africa and Europe, and Mr Raouf Ben Latifa, assistant general manager of MTA, Caterpillar’s representative for Libya and Tunisia.
        DeGolyer and MacNaughton’s CEO and chairman was accompanied by Mr John Hornbrook, assistant general manager of the company’s Reservoir Studies Division.

    • Valeura Energy Inc. Announces Publication of prospectus & proposed LSE admission

      April 17, 2019

      • Valeura Energy Inc. (TSX: VLE) (“Valeura” or the “Company“), the upstream natural gas producer focused on appraising and developing an unconventional gas accumulation in the Thrace Basin of Turkey in partnership with Equinor, is pleased to announce the approval by the UK Listing Authority and publication of a prospectus dated April 17, 2019 (the “Prospectus“), in relation to the proposed admission of the Company’s common shares (the “Shares“) to the Standard Segment of the Official List of the Financial Conduct Authority (“Admission“) and trading on the Main Market of the London Stock Exchange (“LSE“).

        A copy of the Prospectus has been submitted to the National Storage Mechanism and is available for inspection (subject to securities laws) at www.morningstar.co.uk/uk/NSM. A copy of the Prospectus has also been made available on the Investors section of the Company’s corporate website: www.valeuraenergy.com/investor-information/lse-listing/.

        Subject to final approval by the UK Listing Authority, the Company expects that Admission will become effective and that unconditional dealing in the Shares on the LSE is expected to commence on or around April 25, 2019 under the ticker symbol VLU. The Shares will also continue to trade on the Toronto Stock Exchange (the “TSX“). All Shares will become fully fungible between the two exchanges. For clarity, the Company is not issuing any new equity at this time, and accordingly, the additional listing is non-dilutive.

        Rationale

        Valeura’s management and directors believe that the United Kingdom provides an opportunity for the Company to attract greater shareholder interest than is presently available through only its TSX listing. In particular, a listing on the LSE provides access to investors who are mandated to invest in European regulated markets, in addition to generating appeal with a broader range of equity research analysts. Accordingly, Valeura expects this move will elevate its profile amongst its international oil and gas peer group and increase trading liquidity.

        The Company believes its 10.1 Tcfe of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate, attributable to its licenses in the Thrace Basin of Turkey will be attractive to European investors. Early results from the Equinor / Valeura drilling programme at Yamalik-1 and Inanli-1 are encouraging and the Company’s efforts are squarely focused on further de-risking the play with a view towards commercial development. Many European investors the Company has met have demonstrated a strong understanding of Turkish gas market dynamics (including the fact that Turkey imports over 99% of its gas supply), and have expressed a willingness to invest.

        Sean Guest, Presidentand CEO commented:

        “We are delighted to pursue this additional listing on the London Stock Exchange. Our goal is to provide a platform for European and UK investors to participate seamlessly along with our North American shareholders in the next phase of Valeura’s exciting story as we, alongside our partner Equinor, de-risk our unconventional basin-centered gas accumulation play in the Thrace Basin.”

        Advisers

        Valeura has retained GMP FirstEnergy to act as Financial Adviser to the Company on the listing and will act as corporate broker post-admission. In addition, the Company may appoint additional joint brokers at a later date. London law firm Memery Crystal is acting as legal adviser on the listing.

        About Valeura Energy

        Valeura Energy Inc. is a Canada-based public company engaged in the exploration, development and production of petroleum and natural gas in Turkey.

        Since Valeura was established in 2010, the Company has executed a number of transactions and currently holds interests in 20 production leases and exploration licences in the Thrace Basin of Turkey totalling 0.46 MM acres (gross) or on a net basis 0.37 MM acres of shallow rights and 0.26 MM net acres of deep rights.

        Valeura is appraising an unconventional basin-centered gas accumulation play in the Thrace Basin on its deep rights, which has been evaluated by DeGolyer and MacNaughton to hold, effective December 31, 2018, 10.1 Tcfe of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate. By applying 3D seismic, modern reservoir stimulation technology and horizontal and deeper vertical well drilling, Valeura is aiming to achieve commercial scale operations from this tight gas resource.

        In addition, the Company owns an extensive network of gas gathering and sales infrastructure to support direct marketing of natural gas to end users, and in 2018, produced an average of 4.3 MMcf/d of natural gas from conventional gas accumulations in its shallower rights.

        Additional information relating to Valeura is also available on SEDAR at www.sedar.com and on the Company’s corporate website at www.valeuraenergy.com.

        Hard copies of the Prospectus will also be available during normal business hours at the offices of the Company’s UK legal adviser, Memery Crystal LLP, 165 Fleet Street, London EC4Q 2DY, UK.

        For further information please contact:

        Valeura Energy Inc.(General and Investor Enquiries)+1 403 237 7102
        Sean Guest, President and CEO
        Steve Bjornson, CFO
        Robin Martin, Investor Relations Manager
        Contact@valeuraenergy.com, IR@valeuraenergy.com

        GMP First Energy(Financial Adviser and Corporate Broker)+44 (0) 20 7448 0200
        Jonathan Wright, Hugh Sanderson

        CAMARCO (PublicRelations, Media Adviser) +44(0) 20 3757 4980
        Owen Roberts, Billy Clegg, Monique Perks, Thayson Pinedo
        Valeura@camarco.co.uk

        Oil and Gas Advisories& Definitions

        Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

        There is no certainty that any portion of the prospective resources will be discovered. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the prospective resources.

        Please see the Company’s annual information form for the year ended December 31, 2018, which is available under Valeura’s issuer profile on SEDAR at www.sedar.com, for more information with respect to the Company’s prospective resources, including details regarding risked estimates.

        Forward-LookingStatements and Cautionary Statements

        This news release contains certain forward-looking statements and information (collectively referred to herein as “forward-looking information“) including, but not limited to: the proposed Admission and unconditional dealing in the Shares on the LSE (which are subject to the approval of the UK Listing Authority), the timing of such potential Admission and commencement of dealings and the belief that such proposed Admission may bolster value for the Company’s shareholders; the belief that such proposed Admission will provide access to additional investors and that it will generate appeal with a broader range of equity research analysts; the expectation that such proposed Admission will elevate Valeura’s profile amongst its international oil and gas peer group and increase trading liquidity; the potential of the Company’s unconventional basin-centered gas accumulation play in the Thrace Basin; and the Company’s intention to achieve commercial scale operations. Forward-looking information typically contains statements with words such as “anticipate”, “estimate”, “expect”, “target”, “potential”, “could”, “should”, “would” or similar words suggesting future outcomes. The Company cautions readers and prospective investors in the Company’s securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.

        Statements related to “prospective resources” are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding “prospective resources” include volumes of prospective resources and the ability to finance future development and, the conversion of a portion of prospective resources into reserves.

        Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: continued political stability of the areas in which the Company is operating; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government and regulators in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; decline rates; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licenses and leases; and the Company’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programmes and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracking and other specialised oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Company believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

        Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Company including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines and costs for the deep evaluation; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues or civil unrest in Turkey; potential changes in laws and regulations, the uncertainty regarding government and other approvals; counterparty risk; risks associated with weather delays and natural disasters; and the risk associated with international activity. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See the AIF for a detailed discussion of the risk factors.

        Additional information relating to Valeura is also available on SEDAR at www.sedar.com

        This announcement doesnot constitute an offer to sell or the solicitation of an offer to buysecurities in any jurisdiction, including where such offer would be unlawful.This announcement is not for distribution or release, directly or indirectly,in or into the United States, Ireland, the Republic of South Africa or Japan orany other jurisdiction in which its publication or distribution would beunlawful.

        Neither the TorontoStock Exchange nor its Regulation Services Provider (as that term is defined inthe policies of the Toronto Stock Exchange) accepts responsibility for theadequacy or accuracy of this news release.

        This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

        SOURCE: Valeura Energy Inc. https://www.oilandgas360.com/valeura-energy-inc-announces-publication-of-prospectus-proposed-lse-admission/

    • Arrow Exploration Corp. Reports 2018 Year-End Reserves

      April 10, 2019

      • CALGARY, April 8, 2019 /CNW/ – ARROW Exploration Corp. (“Arrow” or the “Company“) (TSXV: AXL) is pleased to report its year-end 2018 reserves in Colombia and Canada as evaluated by DeGolyer and MacNaughton (“D&M“) of Dallas, Texas in its report dated effective as of December 31, 2018 (the “D&M Reserves Report“). This evaluation was prepared using the guidelines outlined in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook“) and is in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“).

        In accordance with the requirements of NI 51-101, the Company expects to file more detailed disclosure relating to its oil and gas activities for the year ended December 31, 2018 in its 2018 Annual Information Form, together with an operational update, audited annual financial statements and management’s discussion and analysis, on or before April 30, 2019.

        Year-End 2018 Company Gross Reserves Highlights

        • 4.97 MMboe of Proved Reserves
        • 10.57 MMboe of Proved plus Probable Reserves
        • Proved Reserves estimated net present value before income taxes of US $56,138,000 calculated at a 10% discount rate
        • Proved plus Probable Reserves estimated net present value before income taxes of US $114,018,000 calculated at a 10% discount rate
        • Reserve Life Index of 8.1 for Proved Reserves and 17.2 for Proved plus Probable Reserves based on average fourth quarter 2018 corporate production of 1,683 boe/d

        Mr. Gary Wine, Chief Executive Officer of Arrow, commented, “We’re very pleased to have increased our reserves in 2018 through the acquisition of assets in Colombia complemented by the success of our first exploration well in Colombia in Q4 2018. Our long Reserve Life Index and large under-developed land position in Colombia positions the Company very well for future growth.”

        A summary of the Company’s Gross Reserves volumes according to reserve category as at December 31, 2018 is provided in the following table. Numbers in this table may not add exactly due to rounding.

        2018 Year-End Company Gross Reserves Volumes (1)

        Reserve Category

        Light &
        Medium
        Crude Oil
        (Mbbl)

        Heavy
        Oil
        (Mbbl)

        Condensate
        (Mbbl)

        Sales
        Gas
        (MMcf)

        NGL
        (Mbbl)

        Total Oil
        Equivalent
        (Mboe)

        Proved Developed Producing

        1,247

        254

        0

        1,699

        12

        1,796

        Proved Developed Non-Producing

        789

        154

        35

        3,366

        36

        1,575

        Proved Undeveloped

        0

        1,598

        0

        0

        0

        1,598

        Total Proved

        2,036

        2,006

        35

        5,065

        48

        4,969

        Probable

        1,475

        3,747

        13

        2,053

        22

        5,599

        Total Proved plus Probable

        3,511

        5,753

        48

        7,118

        70

        10,568

         

        Note:
        (1)   See Oil and Gas Advisories and Reserves Definitions below.

        A summary of the net present value of the Company’s estimated future net revenues associated with the Company’s Gross Reserves as at December 31, 2018 is provided in the following table. The net present values are estimated based on the forecast prices set out below and readers should not assume that the net present values estimated by D&M represent the fair market value of the Company’s Gross Reserves. Numbers in this table may not add exactly due to rounding.

        2018 Year-End Company Gross Reserves Values (1)

        Before Income Taxes Discounted at (% / year)

        Reserves Category

        0% (M
        US $)

        5% (M
        US $)

        10% (M
        US $)

        15% (M
        US $)

        20% (M
        US $)

        Proved Developed Producing

        30,767

        28,406

        26,422

        24,729

        23,278

        Proved Developed Non-Producing

        33,254

        27,485

        23,043

        19,574

        16,815

        Proved Undeveloped

        12,498

        9,093

        6,673

        4,924

        3,641

        Total Proved

        76,519

        64,984

        56,138

        49,227

        43,734

        Probable

        104,207

        76,676

        57,880

        44,694

        35,226

        Total Proved plus Probable

        180,726

        141,660

        114,018

        93,921

        78,960

        Note:
        (1)   The forecast prices used in the calculations of the present value of future net revenue for year-end 2018 are shown below.

         

        Forecast Prices, Cost Escalation Rates and Exchange Rates

        Year

        WTI
        Reference
        Price

        AECO Gas Price

        Edmonton
        Condensate
        Price

        Edmonton
        Propane
        Price

        Edmonton
        Butane
        Price

        Inflation
        Rates

        Exchange
        Rate

        (US $/bbl)

        (CDN
        $/MMBtu)

        (CDN $/bbl)

        (CDN
        $/bbl)

        (CDN
        $/bbl)

        (%/year)

        (US $/CDN
        $)

        Forecast

        2019

        58.58

        1.88

        70.10

        26.13

        27.32

        2.0

        0.757

        2020

        64.60

        2.31

        79.21

        31.27

        41.10

        2.0

        0.782

        2021

        68.20

        2.74

        83.33

        34.58

        49.28

        2.0

        0.797

        2022

        71.00

        3.05

        86.20

        37.25

        55.65

        2.0

        0.803

        2023

        72.81

        3.21

        88.16

        38.73

        57.92

        2.0

        0.807

        2024

        74.59

        3.31

        90.20

        39.75

        59.27

        2.0

        0.808

        2025

        76.42

        3.39

        92.43

        40.76

        60.77

        2.0

        0.808

        2026

        78.40

        3.46

        94.87

        41.93

        62.37

        2.0

        0.808

        2027

        79.98

        3.54

        96.80

        42.84

        63.65

        2.0

        0.808

        2028

        81.59

        3.62

        98.79

        43.80

        64.97

        2.0

        0.808

        2029

        83.22

        3.70

        100.76

        44.73

        66.26

        2.0

        0.808

        2030

        84.87

        3.78

        102.77

        45.64

        67.56

        2.0

        0.808

        2031

        86.57

        3.85

        104.84

        46.56

        68.92

        2.0

        0.808

        2032

        88.30

        3.92

        106.94

        47.46

        70.33

        2.0

        0.808

        2033

        90.08

        4.00

        109.10

        48.44

        71.72

        2.0

        0.808

        2034 +

        +2% / yr

        +2% / yr

        +2% / yr

        +2% / yr

        +2% / yr

        2.0

        0.808

         

        Discussion of the D&M Reserves Report

        On October 1, 2018, the Company announced it had closed its acquisition of Carrao Energy S.A. from Canacol Energy Ltd. as well as the asset purchase of a 50% beneficial interest in the under-developed Tapir Block (collectively, the “Colombian Assets“), and completed the reverse takeover transaction with Arrow Exploration Ltd.

        During the year ended December 31, 2018, the Company recorded increases in all categories of reserves due primarily to the acquisition of the Colombian Assets. Prior to acquiring the Colombian Assets, the Company’s reserves were located entirely in Canada in the Fir and Pepper Montney Fields. The Company’s Gross Proved and Probable Reserves in these fields constituted approximately 12% of the Company’s Gross Proved and Probable Reserves at year-end 2018. Subsequent to the acquisition of the Colombian Assets, Arrow successfully drilled an exploration well, Danes-1, on the LLA-23 Block in the Llanos Basin in Colombia. The Danes-1 well resulted in recognition of 376 Mbbl of Company Gross Proved Reserves and 509 Mbbl of Company Gross Proved plus Probable Reserves as discoveries in the D&M Reserves Report.

        Year-End 2018 Company Gross Reserves Reconciliation

        A reconciliation of the Company’s Gross Reserves volumes according to reserve category as at December 31, 2018 compared to the Company’s Gross Reserves volumes at December 31, 2017 is provided in the following table. Numbers in this table may not add exactly due to rounding.

        TOTAL PROVED

        Light/Medium
        Crude Oil
        (Mbbl)

        Heavy Crude Oil
        (Mbbl)

        Conventional
        Natural Gas (MMcf)

        NGL
        (Mbbl)

        Total Oil
        Equivalent
        (Mboe)

        Opening Balance (December 31, 2017)

        16

        5,371

        125

        1,036

        Extensions

        0

        Improved Recovery

        0

        Technical Revisions

        325

        (6)

        (7)

        (38)

        280

        Discoveries

        376

        376

        Acquisitions

        1,468

        2,160

        3,628

        Dispositions

        (16)

        (109)

        (24)

        (2)

        (131)

        Economic Factors

        (24)

        (24)

        Production

        (109)

        (39)

        (275)

        (2)

        (196)

        Closing Balance (December 31, 2018)

        2,036

        2,006

        5,065

        83

        4,969

        TOTAL PROVED + PROBABLE

        Light/Med
        Crude Oil
        (Mbbl)

        Heavy Crude Oil
        (Mbbl)

        Conventional
        Natural Gas (MMcf)

        NGL
        (Mbbl)

        Total Oil
        Equivalent
        (Mboe)

        Opening Balance (December 31, 2017)

        23

        7,707

        175

        1,483

        Extensions

        0

        Improved Recovery

        0

        Technical Revisions

        (296)

        136

        (279)

        (52)

        (259)

        Discoveries

        509

        509

        Acquisitions

        3,452

        6,240

        9,692

        Dispositions

        (23)

        (578)

        (35)

        (3)

        (610)

        Economic Factors

        (45)

        (6)

        (51)

        Production

        (109)

        (39)

        (275)

        (2)

        (196)

        Closing Balance (December 31, 2018)

        3,511

        5,753

        7,118

        118

        10,568

         

        About ARROW Exploration

        Arrow Exploration Corp. (operating in Colombia via a branch of its 100% owned subsidiary Carrao Energy S.A.) is a publicly-traded company with a portfolio of Colombian oil assets that are underexploited, underexplored and may offer high potential growth. The Company’s business plan is to rapidly expand oil production from some of Colombia’s most active basins, including the Llanos, Middle Magdalena Valley and Putumayo Basin. The Company’s asset base is predominantly operated with high working interests and typically realizes Brent-linked pricing exposure. Arrow’s management is led by a hands-on and in-country executive team supported by an experienced board.  Arrow is listed on the TSX Venture Exchange under the symbol “AXL”.

        OIL AND GAS ADVISORIES

        D&M Reserves Report

        The D&M Reserves Report was prepared using guidelines outlined in the COGE Handbook and in accordance with NI 51-101.

        boe

        A boe is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Further, a conversion ratio of 6 Mcf:1 boe assumes that the gas is very dry without significant natural gas liquids. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

        RESERVES DEFINITIONS

        With respect to the reserves data contained herein, the following terms have the meanings indicated:

        Company Gross Reserves” are the Company’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company.

        developed” reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

        developed producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

        developed non-producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

        possible” reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

        probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

        proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

        reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

        undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.

        OTHER DEFINITIONS

        bbl means barrel.

        boe means barrel of oil equivalent.

        boe/d means barrel of oil equivalent per day.

        CDN $ means Canadian dollars.

        Mbbl means thousand barrels.

        Mboe means thousand barrels of oil equivalent.

        Mcf means thousand cubic feet.

        MMboe means million barrels of oil equivalent.

        MMcf means million cubic feet.

        MM US $ means million United States dollars.

        M US $ means thousand United States dollars.

        Reserve Life Index is calculated by dividing the Company’s Gross Reserves by working interest production for the year, which, in 2018, is based on fourth quarter average working interest production of 1,683 boe/d. This metric expresses how long a company’s reserves will last at the current production rate with no additions to reserves.

        US $ means United States dollars.

        FORWARD-LOOKING STATEMENTS

        This press release contains certain forward-looking statements within the meaning of applicable securities laws. Forward-looking statements are frequently characterized by words such as “plan”, “expect”, “project”, “target”, “intend”, “believe”, “anticipate”, “estimate” and other similar words, or statements that certain events or conditions “may”, “should” or “will” occur. In particular, this press release contains forward-looking statements pertaining to, among other things, the following: the timing of the release, and filing (as applicable), of Arrow’s Form 51-101F1, comprehensive operational update and year-end financial statements; Arrow’s business plan; and Arrow’s asset base and price exposure.

        Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.

        All forward-looking statements are based on Arrow’s beliefs and assumptions based on information available at the time the assumption was made. Arrow believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this press release should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks and assumptions discussed in the Company’s Management’s Discussion and Analysis for the three months ended September 30, 2018, under the headings “Risks and Uncertainties” and “Forward-Looking Statements“. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Arrow’s future course of action depends on management’s assessment of all information available at the relevant time.

        Any “financial outlook” or “future oriented financial information” in this press release, as defined by applicable securities legislation has been approved by management of Arrow. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

        Additional information on these and other factors that could affect Arrow’s operations or financial results are included in Arrow’s reports on file with Canadian securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise. Arrow undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law. All subsequent forward-looking statements, whether written or oral, attributable to Arrow or persons acting on the Company’s behalf are expressly qualified in their entirety by these cautionary statements.

        RESERVES AND DRILLING DATA

        This press release contains oil and gas metrics that are commonly used in the oil and gas industry such as “reserve life index”. These metrics have been prepared by management of the Company and do not have standardized meanings or standardized methods of calculation and therefore such measures may not be comparable to similar measures presented by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company, and future performance may not compare to the performance in prior periods and therefore such metrics should not be unduly relied upon. The Company uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented herein, should not be relied upon for investment purposes.

        There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas and NGL reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

        Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. This press release contains estimates of the net present value of the Company’s future net revenue from our reserves. Such amounts do not represent the fair market value of the Company’s reserves. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

        Neither the TSX Venture Exchange (TSXV) nor its regulation services provider (as that term is defined in the policies of the TSXV) accepts responsibility for the adequacy or accuracy of this release.

        SOURCE ARROW Exploration Corp.

    • Bahrain Seeks US Partners for Offshore Shale Discovery

      April 5, 2019

      • Home to the oil and gas talent base that has successfully developed world-class unconventional resource plays such as the Permian Basin and the Eagle Ford Shale, Texas boasts a formidable storehouse of world-class expertise within its extensive borders.

        The smallest country in the Middle East wants to import some of that Texas-sized know-how to develop a massive oil and gas discovery.

        Shaikh Mohamed bin Khalifa Al-Khalifa, Bahrain’s oil minister who leads the island kingdom’s National Oil and Gas Authority (NOGA), is visiting the Lone Star State this week to entice U.S. operating and service companies to consider doing business in the Arabian Gulf country.

        In 2018, NOGA announced the kingdom’s largest-ever oil and gas discovery in the shallow waters of the Khalij Al-Bahrain Basin. The ministry, working alongside DeGolyer and MacNaughton, Halliburton and Schlumberger to assess the find, has reported that the discovery could hold at least 80 billion barrels of tight oil in place – on a P50 basis – and deep gas reserves ranging from 10 to 20 trillion cubic feet.

        According to a Columbia University Center on Global Energy Policy commentary written by the CEO of consulting firm Qamar Energy, Bahrain would claim a milestone for the oil and gas industry by developing the resource: the first instance of commercial offshore shale oil production. The feat, however, would not mark Bahrain’s first claim to fame in the industry. Standard Oil of California in 1932 made the first Arabian Gulf oil discovery in Bahrain, Al-Khalifa noted.

        “This discovery is obviously an opportunity to increase production of oil but also rich gas – like in Texas with the Eagle Ford and Permian and ethane and other natural gas liquids,” Al-Khalifa told Rigzone. “We’re close to some of the region’s largest ethane processing facilities.”

        For instance, Al-Khalifa pointed out that Bahrain is close to some of the Middle East’s largest petrochemicals sites – such as Dow Chemical Co. and Saudi Aramco’s Sadara complex in Jubail Industrial City, Saudi Arabia.

        Calling unconventional oil and gas production “very much a U.S.-based phenomenon,” Al-Khalifa pointed out that he and other Bahraini officials held earlier meetings with U.S. players last summer. This time around, they are collaborating in talks with operating and service companies as well as entities such as the American Chamber of Commerce (AmCham) and the U.S. Chamber of Commerce.

        “We’re trying to learn from the phenomenon that happened here and see if we can attract some of the companies to locate in Bahrain,” said Al-Khalifa, adding that the kingdom has set up a virtual data room and has “invested money” to better explain the quality of the resource to interested parties. “We’re collecting information and trying to set up the right structure for companies to invest. We want them to make money and apply their technologies.”

        Al-Khalifa added that Bahrain’s free trade agreement with the United States, coupled with its close proximity to Saudi Arabia and other Gulf Cooperation Council countries, make the kingdom a good launching pad for business opportunities in the region. Moreover, he noted that Bahrain boasts a “very liberal and relaxed environment for foreign companies.”

        “It’s an easy place to set up shop” for companies of various sizes, said Al-Khalifa, adding that the kingdom is also looking at the possibility of direct flights to Houston to facilitate trade ties.

        The oil minister declined to reveal specifics tied to ongoing analysis of the discovery, but he said that early signs appear positive. A pair of rigs, one operated by Helmerich and Payne and another by Trinidad Drilling, are currently mobilized under a two-year drilling program to evaluate the resource.

        “I think it’s a bit too early to throw out (anticipated) production numbers, but I can tell you the quality of the rock is very superior,” Al-Khalifa said. “We’re drilling a few wells to make the data available. It is the source rock that gave you the largest oil field in the world.”

        According to a 2018 NOGA written statement, Bahrain officials aim to have the discovery on production within five years.

        https://www.rigzone.com/news/bahrain_seeks_us_partners_for_offshore_shale_discovery-05-apr-2019-158530-article/

    • ROAN RESOURCES, INC. filed on Mon, April 01 10-K

      April 1, 2019

      • ROAN RESOURCES, INC. filed 10-K with SEC. Read ‘s full filing at 000132642819000006.

        Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% working interest in 100 acres owns 50 net acres.

        PV-10. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows.

        Standardized measure. Discounted future net cash flows estimated by applying year end prices to the estimated future production of year end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

        Reorganization. Refers to the reorganization transactions contemplated by the master reorganization agreement, dated September 17, 2018, by and among Linn Energy, Inc., Roan Holdings, LLC, and Roan Resources LLC, pursuant to which New Linn’s and Roan Holdings’ respective 50% equity interest in Roan LLC were moved under Roan Inc.

        Riviera Separation. Refers to the reorganization transactions pursuant to which Old Linn contributed certain of its assets to Riviera except for its 50% equity interest in Roan LLC, as further described in Reorganization.

        Our predecessor, Roan LLC, was initially formed by Citizen in May 2017. In June 2017, subsidiaries of Old Linn, together with Citizen and Roan LLC entered into the Contribution, pursuant to which, among other things, Old Linn and Citizen agreed to contribute certain oil and natural gas assets to Roan LLC, each in exchange for a 50% equity interest in Roan LLC. On August 31, 2017, Old Linn and Citizen consummated the transactions contemplated by such contribution agreement. Following these transactions, Citizen’s equity interest in Roan LLC was held through its wholly-owned subsidiary, Roan Holdings.

        In the third quarter of 2018, Old Linn and certain of its subsidiaries undertook an internal reorganization, pursuant to which Old Linn merged with and into a wholly-owned subsidiary of New Linn. Following such internal reorganization, New Linn completed the spin-off of substantially all of its assets, other than its 50% equity interest in Roan LLC.

        On September 17, 2018, New Linn, Roan Holdings and Roan LLC entered into a master reorganization agreement, to effectuate the reorganization of New Linn’s and Roan Holdings’ respective 50% equity interests in Roan LLC under Roan Inc. On September 24, 2018, the Company consummated the Reorganization, which resulted in the existing stockholders of New Linn receiving 50% of the Class A common stock of the Company and Roan Holdings receiving 50% of the Class A common stock of the Company. In connection with the Reorganization, the Company became the owner, indirectly through its wholly-owned subsidiaries, of 100% of the equity in, and is the sole manager of, Roan LLC. The Company is responsible for all operational, management and administrative decisions relating to Roan LLC’s business.

        As of December 31, 2018, we held leasehold interests in approximately 383,000 gross (172,000 net) acres in the Anadarko Basin. At December 31, 2018, our total estimated proved reserves were approximately 305,959 MBoe. For the quarter ended December 31, 2018, our average net daily production was 54.1 MBoe/ d (approximately 27% oil, 42% natural gas and 31% NGLs).

        •Maintain a high degree of operational control to facilitate efficient development and capital budgeting. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of December 31, 2018, we operated approximately 71% of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns.

        Maintain a high degree of operational control to facilitate efficient development and capital budgeting. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of December 31, 2018, we operated approximately 71% of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns.

        •Large, contiguous acreage position in the core of the Merge play with significant operational control. We are the largest leaseholder in the Merge play, with approximately 115,000 net acres as of December 31, 2018. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately 80% of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of December 31, 2018, we operated 81% of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value.

        Large, contiguous acreage position in the core of the Merge play with significant operational control. We are the largest leaseholder in the Merge play, with approximately 115,000 net acres as of December 31, 2018. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately 80% of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of December 31, 2018, we operated 81% of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value.

        •Significant financial strength and flexibility. We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately 84% of our acreage is HBP as of December 31, 2018. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.

        Significant financial strength and flexibility. We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately 84% of our acreage is HBP as of December 31, 2018. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.

        •High Degree of Operational Control. We expect that we will be able to control operations on approximately 71% of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.

        High Degree of Operational Control. We expect that we will be able to control operations on approximately 71% of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.

        •Contiguous Acreage Position. A substantial portion of the sections in which we have operational control are offset to the north or south by adjacent controlled sections. Specifically, approximately 66% of our sections in the Merge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of our drilling program, which we believe have exhibited superior economics as compared to shorter laterals as a result of development cost efficiencies.

        Contiguous Acreage Position. A substantial portion of the sections in which we have operational control are offset to the north or south by adjacent controlled sections. Specifically, approximately 66% of our sections in the Merge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of our drilling program, which we believe have exhibited superior economics as compared to shorter laterals as a result of development cost efficiencies.

        •Largely Held-by-Production. Approximately 84% of our total acreage position was HBP as of December 31, 2018. We expect this high percentage of HBP acreage to enhance capital efficiencies in our development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.

        Largely Held-by-Production. Approximately 84% of our total acreage position was HBP as of December 31, 2018. We expect this high percentage of HBP acreage to enhance capital efficiencies in our development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.

        We refer to gross and net acreage where we are designated as operator or expect to be designated as operator based on the size of our working interest relative to other working interest owners as ‘our operated acreage’ or acreage we ‘operated’ in this Annual Report. As of December 31, 2018, we operated approximately 71% of our net acreage and had an average working interest of approximately 70% in all of our operated acreage. From January 1, 2018 through December 31, 2018, we drilled or participated in 214 gross horizontal wells that had first sales as of December 31, 2018.

        As of December 31, 2018, approximately 84% of our total net acreage was held by production. This positions us to control the pace of our development efforts, strategically develop our acreage with a near-term focus on high-return projects, limit expenditures on lease renewals and limit the risk of losing high quality acreage through expiration of leases. Additionally, we closely monitor activity of other industry participants and adjust our future development plans based on information and what we believe to be best practices learned from our peers.

        For the year ended December 31, 2018, our average net daily production was 43.7 MBoe/d (approximately 27% oil, 44% natural gas and 29% NGLs). During 2017, our average net daily production was 16.2 MBoe/d (approximately 25% oil, 49% natural gas and 26% NGLs). As of December 31, 2018, we had 1,263 gross (502 net) producing wells online, operated and non-operated.

        Evaluation of Proved Reserves. Approximately 93% of our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018.

        Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. As of December 31, 2018, approximately 84% of our total net acreage was held by production.

        The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25.0%, resulting in a net revenue interest to us generally ranging from 74% to 81% of our working interest, with an average net revenue interest of 78.9%.

        The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market based rate authority (demonstrating the pipeline lacks market power), establishing rates by settlement with all existing shippers, or through a cost of service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for us.

        Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of December 31, 2018, we had $514.6 million of debt outstanding, with a weighted average interest rate of 5.21%, and a 1.0% increase in interest rates would result in an increase in annual interest expense of $5.1 million, assuming no change in the amount of debt outstanding. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

        Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, will determine semiannually on April 1st and October 1st of each year. The borrowing base will depend on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our credit facility and hedging arrangements. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base will require the consent of the lenders holding 100% of the commitments.

        As of December 31, 2018, approximately 61% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to lose leases through expiration or could cause us to reclassify our PUDs as unproved reserves. Further, we may be required to write down our PUDs if we do not drill those wells within five years after their respective dates of booking.

        Approximately 16% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

        As of December 31, 2018, approximately 16% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. Further, to the extent we determine that it is not economic to develop particular undeveloped acreage, we may intentionally allow leases to expire.

        Our top four customers represented approximately 77% of our total revenue for the year ended December 31, 2018. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers for the foreseeable future. Loss of one of these purchasers could adversely affect our revenues in the short term.

        Our principal stockholders and their affiliates beneficially own approximately 75% (50% of which is beneficially owned by Roan Holdings) of our outstanding Class A common stock. Consequently, they will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. Because our board will be classified through the 2020 annual meeting, certain of our directors will not come up for election until after the 2020 annual meeting. This concentration of ownership and the rights of our principal stockholders will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

        among other things, potential competitive business activities or business opportunities. Several of our principal stockholders are private equity firms or investment funds in the business of making investments in entities in a variety of industries. As a result, our principal stockholders’ existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor. Certain of our principal stockholders owning approximately 25% of our outstanding Class A common stock own a significant interest in Riviera, the owner of Blue Mountain.

        •Average daily sales volumes were 43.7 MBoe for the year ended December 31, 2018, an increase of 170% compared to 16.2 MBoe during 2017.

        Average daily sales volumes were 43.7 MBoe for the year ended December 31, 2018, an increase of 170% compared to 16.2 MBoe during 2017.

        Production taxes. Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. As all of our oil and natural gas production is in the state of Oklahoma, we are generally subject to a tax rate of 2% for the first 36 months of production and 7% thereafter for wells spud on or after July 1, 2015. Starting with July 2018 production, the tax rate increased to 5% for the first 36 months of production and 7% thereafter. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.

        Oil sales. Our oil sales increased by approximately $198.4 million, or 258%, to $275.2 million for the year ended December 31, 2018 from $76.9 million for the year ended December 31, 2017. This increase was primarily due to the increase in production as well as the increase in average sales prices received for our produced volumes. Our oil production increased 2,910 MBbls, or 200%, to 4,364 MBbls for the year ended December 31, 2018 from 1,454 MBbls for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The increase in average sales prices received on our oil production for the year ended December 31, 2018 reflects the increase in the index price for oil in 2018 as compared to 2017.

        Natural gas sales. Our natural gas sales increased by approximately $26.8 million, or 55%, to $76.1 million for the year ended December 31, 2018 from $49.2 million for the year ended December 31, 2017. This increase was primarily due to the increase in production, partially offset by a decrease in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production increased 24,308 MMcf, or 138%, to 41,890 MMcf for the year ended December 31, 2018 from 17,582 MMcf for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The decrease in average sales prices received on our natural gas production for the year ended December 31, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in 2018 as compared to 2017. Additionally, our average sales price for the year ended December 31, 2018 was reduced by transportation costs for the produced natural gas volumes.

        Production expenses. Production expenses were $47.6 million, or $2.99 per Boe, for the year ended December 31, 2018, which was an increase of $30.7 million, or 182%, from $16.9 million, or $2.86 per Boe, for the year ended December 31, 2017. The increase in production expenses during 2018 compared to 2017 was primarily due to increased production.

        Production taxes. Production taxes were $17.6 million for the year ended December 31, 2018, an increase of $13.9 million, or 377%, from $3.7 million for the year ended December 31, 2017. Production taxes primarily increased due to increased revenues and increased production tax rates, which became effective in July 2018.

        Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $123.9 million, or $7.78 per Boe, for the year ended December 31, 2018, and $37.4 million, or $6.33 per Boe, for the year ended December 31, 2017, which is an increase of $86.5 million or 232%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production and, to a lesser extent, an increase in the depletion rate for our oil and natural gas properties. The per Boe increase in the depletion rate is attributable to higher capital expenditures in 2018.

        General and administrative. General and administrative expenses were $60.9 million, or $3.82 per Boe, for the year ended December 31, 2018, an increase of $29.5 million or 94% from $31.4 million, or $5.31 per Boe, for the year ended December 31, 2017. During the year ended December 31, 2018, general and administrative expenses included salaries and benefits of $21.7 million and equity-based compensation expense of $11.0 million. Additionally, we incurred consulting and professional fees as part of the implementation of systems and processes and transition efforts in 2018 as well as $4.6 million of costs associated with the Reorganization. These expenses were offset by bonuses paid by Citizen of approximately $9.0 million during the year ended December 31, 2017.

        Natural gas sales. Our natural gas sales increased by approximately $33.1 million, or 206%, to $49.2 million for the year ended December 31, 2017 from $16.1 million for the year ended December 31, 2016. This increase was due to increased production and an increase in average sales prices received for our produced volumes. Our natural gas production increased by 11,200 MMcf, or 175%, for the year ended December 31, 2017 compared with the year ended December 31, 2016. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in 2017. The increase in average sales prices received on our natural gas production for the year ended December 31, 2017 reflects the increase in the index price for the year ended December 31, 2017 as compared to the year ended December 31, 2016.

        NGL sales. Our NGL sales increased by approximately $32.0 million, or 385%, to $40.3 million for the year ended December 31, 2017 from $8.3 million for the year ended December 31, 2016. This increase was primarily due to increased production as well as an increase in average sales prices received for our produced volumes. Our NGL production increased by 978 MBbls, or 179%, for the year ended December 31, 2017 compared with the year ended December 31, 2016. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in 2017. The increase in average sales prices received on our NGL production for the year ended December 31, 2017 reflects the increase in the index prices for NGLs in 2017.

        Production expenses. Production expenses were $16.9 million, or $2.86 per Boe, for the year ended December 31, 2017, which was an increase of $11.8 million, or 231%, from $5.1 million, or $2.17 per Boe, for the year ended December 31, 2016. The increase in production expenses during 2017 compared to 2016 was primarily due to increased production.

        Gathering, transportation and processing. Gathering, transportation, and processing costs were $18.6 million, or $3.15 per Boe, for the year ended December 31, 2017, which was an increase of $12.7 million, or 215%, from $5.9 million, or $2.52 per Boe, for the year ended December 31, 2016. The increase in gathering, transportation and processing costs during 2017 as compared to 2016 was primarily related to increased production.

        Production taxes. Production taxes were $3.7 million for the year ended December 31, 2017, which was an increase of $2.6 million, or 239%, from $1.1 million for the year ended December 31, 2016. Production taxes primarily increased due to increased revenues.

        Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $37.4 million, or $6.33 per Boe, for the year ended December 31, 2017, which was an increase of $12.4 million, or 50%, from $25.0 million, or $10.64 per Boe, for the year ended December 31, 2016. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production.

        General and administrative. General and administrative expenses were $31.4 million, or $5.31 per Boe, for the year ended December 31, 2017, which was an increase of $25.8 million, or 462%, from $5.6 million, or $2.38 per Boe, for the year ended December 31, 2016. During the year ended December 31, 2017, general and administrative expenses included fees paid to Citizen and Linn under our MSAs of $10.0 million, bonuses paid by Citizen of approximately $9.0 million, equity-based compensation expense of $0.4 million and professional and consulting expenses related to Roan’s transition and system implementation.

        Amounts borrowed under the credit facility bear interest at London Interbank Offered Rate (‘LIBOR’) or the alternate base rate (‘ABR’) at our election. The rate used for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or the one-month LIBOR rate plus 1%. Either rate is adjusted upward by an applicable margin (ranging from 2.00% to 3.00% for LIBOR and 1.00% to 2.00% for ABR), based on the utilization percentage of the credit facility. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50% based on utilization, which is payable at the end of each calendar quarter.

        The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, we are prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon our internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, we are required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per our most recent reserve report.

        (1) Includes interest expense on our outstanding borrowings calculated using the weighted average interest rate of 5.21% at December 31, 2018.

        Proved reserves are based on the quantities of oil, natural gas and NGL that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Our reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers, and our internal staff. DeGolyer and MacNaughton prepared reserve estimates for 93% of our total reserves.

        At December 31, 2018, we had a net asset position of $101.8 million related to our derivative contracts. Utilizing actual derivative contractual volumes under our fixed price swaps as of December 31, 2018, an increase of 10% in the forward curves associated with the underlying commodity would have decreased the net asset position to $55.9 million, while a decrease of 10% in the forward curves associated with the underlying commodity would have increased the net asset position to $159.7 million.

        As of December 31, 2018, we had $514.6 million in outstanding borrowings under our credit facility with a weighted average interest rate on these borrowings of 5.21%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $5.1 million based on outstanding borrowings of $514.6 million under our credit facility as of December 31, 2018.

        Roan LLC was initially formed by Citizen Energy II, LLC (‘Citizen’) in May 2017. On August 31, 2017, the Company executed a contribution agreement (the ‘Contribution Agreement’) by and among Roan LLC, Citizen, Linn Energy Holdings, LLC (‘LEH’) and Linn Operating, LLC (‘LOI’, and together with LEH, ‘Linn’) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest to the Company (collectively the ‘Contribution’). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in Roan LLC.

        In 2018, the Company adopted a 401(k) retirement plan and health and welfare benefit plans in which our employees are eligible to participate. Under the 401(k) retirement plan, the Company provides for an employer match of employee contributions of up to 6% of eligible compensation and a profit-sharing contribution of up to 8% of eligible compensation. For the year ended December 31, 2018, the Company paid $1.2 million in contributions to the plan.

        As noted in Note 1 – Business and Organization, in connection with the Contribution, Roan LLC acquired from Linn certain oil and natural gas properties located in Central Oklahoma (the ‘Linn Acquisition’). In exchange for the contributed oil and natural gas properties, Linn received a 50% equity interest in Roan LLC valued at approximately $1.3 billion based on the value of the business. Accordingly, the fair value of the Company was primarily comprised of the fair value of these contributed oil and natural gas properties. See Note 10 – Equity for further discussion of the equity issued to Linn.

        (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%.

        In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the ‘2017 Credit Facility’). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of December 31, 2018, the Company had $514.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. At December 31, 2018, the weighted average interest rate on borrowings under our 2017 Credit Facility was 5.21%. The 2017 Credit Facility is secured by substantially all of the assets of the Company.

        The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (‘LIBOR’) and alternate base rate (‘ABR’) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375%.

        The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report.

        For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the ‘LLC Units’) for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest in Roan LLC, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn.

        For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the ‘Citizen Operating Agreement’), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B interests. Class A interests represented capital interests in Citizen and Class B interests represented interests in profits, losses and distributions. Distributions were made to the Class A interests and Class B interests members pro rata in accordance with their membership interests; however, once the Class A interests members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B interests members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

        Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the ‘PSUs,’ and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (‘Performance Period End Date’). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs.

        The Company’s effective combined U.S. federal and state income tax rate for the year ended December 31, 2018 excluding discrete items was 24.3%. During the year ended December 31, 2018, the Company recognized income tax expense of $356.9 million, including $304.5 million related to the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization.

        (2)Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3%.

        Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3%.

        https://whatsonthorold.com/2019/04/01/roan-resources-inc-filed-on-mon-april-01-10-k/

    • Approach Resources Inc. Reports Fourth Quarter and Full-Year 2018 Financial and Operating Results

      March 20, 2019

      • Approach Resources Inc. AREX, -29.16% today reported financial and operational results for the fourth quarter and full-year 2018, estimated year-end 2018 proved reserves and provided an update on its efforts to pursue deleveraging alternatives.

        Fourth Quarter 2018 Highlights

        • Fourth quarter production of 963 MBoe or 10.5 MBoe/d
        • Net income was $0.9 million, or $0.01 per diluted share. Adjusted net loss (non-GAAP) was $6.9 million, or $0.07 per diluted share
        • EBITDAX (non-GAAP) of $13.5 million
        • Cash operating expenses (non-GAAP) of $8.85 per Boe, a 28% decrease over the prior quarter

        Full-Year 2018 Highlights

        • Full year production of 4,082 MBoe or 11.2 MBoe/d
        • Year-end 2018 proved reserves 180.1 MMBoe, an increase in oil reserves of 5% over the prior year
        • Drilled six and completed nine horizontal Wolfcamp wells during the year with an inventory of seven drilled and uncompleted wells at year-end
        • Net loss was $19.9 million, or $0.21 per diluted share. Adjusted net loss (non-GAAP) was $25 million, or $0.26 per diluted share
        • EBITDAX (non-GAAP) of $59 million, a 7% increase over the prior year
        • Revenue of $114 million, an 8% increase over the prior year
        • Unhedged cash margin (non-GAAP) of $16.19 per Boe, a 16% increase over the prior year

        Adjusted net loss, EBITDAX, cash operating expenses and unhedged cash margin are non-GAAP measures. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and reconciliations of adjusted net loss and EBITDAX to net income (loss) and unhedged cash margin to revenues.

        Management Comment

        Ross Craft, Approach’s Chairman and CEO, commented, “Due in part to the sharp decline in commodity prices and extreme WAHA gas discount in the basin in the fourth quarter, we focused on conserving capital and reducing our cash operating expenses during the quarter. Additionally, we continued to evaluate alternatives to reduce our leverage. In 2019, we will continue to focus on alternatives to strengthen our balance sheet and manage our covenants under our credit facility. Our capital expenditure budget is designed to be funded primarily through cash flows from operations. As a result of the current commodity price environment, as well as our focus on addressing our leverage, we do not expect any significant drilling and completion activity in the first quarter of 2019.”

         

        Company Continues to Explore Deleveraging Alternatives

        In order to improve our leverage position to meet upcoming financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders, stockholders or bond holders. If we do not accomplish one or more of the deleveraging transactions discussed below, we do not believe we will be able to comply with the total leverage ratio covenant in our revolving credit facility beginning with the measurement date of March 31, 2019.

        On April 12, 2018, our largest shareholder, Wilks Brothers, LLC, and its affiliate SDW Investments, LLC (collectively, “Wilks”), disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million of 7% Senior Notes due 2021 (the “Senior Notes”) currently held by Wilks (the “Exchange Transaction”). In April 2018, our board of directors formed a committee of independent directors (the “Committee”) to evaluate a potential Exchange Transaction as well as other strategic alternatives (the “Competing Transactions”). The Committee hired financial and legal advisors to advise the Committee on these matters. The Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.

        In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.

        In March 2019, our board of directors expanded the scope of the Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Committee has re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. We currently are in discussions with our CEO regarding his separation from the Company. We expect to engage in discussions with our President and Chief Administrative Officer regarding their continued employment or potential separation. The Company is evaluating plans for succession. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.

        If an event of default under our credit facility occurred, our lenders could accelerate the maturity of the outstanding indebtedness, making it immediately due and payable, and we would not have sufficient liquidity to repay those amounts. However, we believe we have adequate liquidity for current, near-term working capital needs from cash generated from operations and, to the extent available, unused borrowing capacity under our revolving credit facility, each assuming (i) no reduction in our borrowing base from our semi-annual borrowing base redetermination and (ii) no acceleration of amounts due under our revolving credit facility.

        Fourth Quarter 2018 Results

        Production for fourth quarter 2018 totaled 963 MBoe (10.5 MBoe/d), made up of 26% oil, 35% NGLs and 39% natural gas. Average realized commodity prices for fourth quarter 2018, before the effect of commodity derivatives, were $55.23 per Bbl of oil, $19.91 per Bbl of NGLs and $0.79 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $22.86 per Boe for fourth quarter 2018.

        Net income for fourth quarter 2018 was $0.9 million, or $0.01 per diluted share, on revenues of $22.4 million. Excluding the increase in the fair value of our commodity derivatives of $10.1 million, adjusted net loss (non-GAAP) for fourth quarter 2018 was $6.9 million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2018 was $13.5 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net income.

        Lease operating expense (“LOE”) averaged $5.21 per Boe. Production and ad valorem taxes averaged $1.80 per Boe, or 7.7% of oil, NGLs and gas sales. Exploration costs were $0.43 per Boe. Total general and administrative (“G&A”) costs averaged $2.80 per Boe, including cash G&A costs of $1.84 per Boe. Depletion, depreciation and amortization expense averaged $14.96 per Boe. Interest expense totaled $6.6 million.

        Full-Year 2018 Results

        Production for 2018 was 4,082 MBoe (11.2 MBoe/d), made up of 26% oil, 36% NGLs and 38% natural gas. Average realized commodity prices for 2018, before the effect of commodity derivatives, were $62.04 per Bbl of oil, $23.28 per Bbl of NGLs and $1.49 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $26.21 per Boe for 2018.

        Net loss for 2018 was $19.9 million, or $0.21 per diluted share, on revenues of $114 million. Excluding the increase in fair value of our commodity derivatives of $6.7 million, adjusted net loss (non-GAAP) for 2018 was $25 million, or $0.26 per diluted share. EBITDAX (non-GAAP) for 2018 was $59 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

        LOE averaged $5.18 per Boe. Production and ad valorem taxes averaged $2.19 per Boe, or 7.8% of oil, NGLs and gas sales. Exploration costs were $0.10 per Boe. Total G&A costs averaged $5.13 per Boe, including cash G&A costs of $4.38 per Boe. Depletion, depreciation and amortization expense averaged $15.05 per Boe. Interest expense totaled $25.1 million.

        Operations Update

        In light of continued commodity price deterioration and the extreme WAHA gas discount in the basin, we deferred third and fourth quarter 2018 drilling and completion activities, and incurred capital expenditures of $0.2 million in the fourth quarter.

        In 2018, we focused on executing a disciplined capital budget and managing natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During 2018, we drilled six and completed nine horizontal Wolfcamp wells. Of these, three wells were completed in the A bench, three wells were completed in the B bench and three wells were completed in the C bench. At December 31, 2018, we had seven horizontal wells waiting on completion.

        Our extensive infrastructure network of centralized production facilities, water transportation, handling and recycling system, gas lift lines and salt water disposal wells continues to provide sustainable competitive advantages and environmentally responsible facility operations. In 2018, we maintained an industry leading average drilling and completion cost of $4.6 million per horizontal well and LOE per Boe of $5.18.

        Fourth Quarter and Full-Year 2018 Production

        Fourth quarter 2018 production totaled 963 MBoe (10.5 MBoe/d). Full-year 2018 production totaled 4,082 MBoe (11.2 MBoe/d).

        Three and 12 Months Ended
        December 31, 2018
        Three months 12 months
        Production:
        Oil (MBbls) 251 1,070
        NGLs (MBbls) 338 1,443
        Gas (MMcf) 2,240 9,408
        Total (MBoe) 963 4,082
        Total (Mboe/d) 10.5 11.2

        2018 Estimated Proved Reserves and Costs Incurred

        Year-end 2018 proved reserves totaled 180.1 MMBoe. Year-end 2018 proved reserves were 29% oil, 31% NGLs and 40% natural gas. Proved developed reserves represent approximately 37% of total year-end 2018 proved reserves.

        At December 31, 2018, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2018 estimated proved reserves included 168.2 MMBoe attributable to the horizontal Wolfcamp shale play.

        Extensions and discoveries for 2018 were 35 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2018, we reclassified 33.1 MMBoe of proved undeveloped reserves to unproved reserves. The reclassified reserves are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 0.2 MMBoe resulting from updated well performance and technical parameters, and an increase of 1.9 MMBoe due to higher commodity prices, partially offset by a decrease of 1.4 MMBoe due to an increase in operating expenses and natural gas price differentials.

        The following table summarizes the changes in our estimated proved reserves during 2018.

        Oil NGLs Natural Gas Total
        (MBbls) (MBbls) (MMcf) (MBoe)
        Balance — December 31, 2017 50,060 57,948 441,228 181,545
        Extensions and discoveries 14,572 8,819 69,362 34,951
        Production(1) (1,070 ) (1,443 ) (10,793 ) (4,312 )
        Revisions to previous estimates (11,104 ) (8,788 ) (73,359 ) (32,117 )
        Balance — December 31, 2018 52,458 56,536 426,438 180,067

        (1) Production includes 1,385 MMcf related to field fuel.

        Our preliminary, unaudited estimate of the standardized after-tax measure of discounted future net cash flows (“standardized measure”) of our proved reserves at December 31, 2018, was $660 million. The PV-10 (non-GAAP), or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2018, was $761.8 million.

        The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2018 proved reserves and PV-10 at SEC pricing. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition of PV-10 and reconciliation to the standardized measure (GAAP). Our reserve estimates and our calculation of standardized measure and PV-10 are based on the 12-month average of the first-day-of-the-month pricing of $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of natural gas during 2018.

        Capital Expenditures

        Fourth quarter capital expenditures were $0.2 million. Net capital expenditures incurred during 2018 totaled $46.8 million and were attributable to drilling and development ($39.4 million), infrastructure projects and equipment ($6.6 million), exploratory project ($0.4 million) and acreage acquisitions and extensions ($0.4 million).

        Liquidity Update

        At December 31, 2018, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million, and liquidity of $23.2 million. Our credit facility is subject to scheduled redeterminations of our borrowing base semi-annually, based on our reserves. Our next anticipated redetermination is expected to take place in the second quarter of 2019, although our lender has the option to redetermine our borrowing base outside of our anticipated schedule. Continued low commodity prices may adversely impact the results of the upcoming redetermination, and have a significant negative impact on the Company’s liquidity. If our borrowing base is reduced below the amount outstanding under our credit agreement, we may be required to repay a portion of our outstanding borrowings, and we may not have sufficient liquidity to meet this requirement. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition and calculation of liquidity.

        Commodity Derivatives Update

        We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. At present, approximately 19% of 2019 forecasted oil and 19% of NGL production is hedged. The table below is a summary of our current derivatives positions.

        Contract
        Commodity and Period Type Volume Transacted Contract Price
        Crude Oil
        January 2019 — December 2019 Collar 500 Bbls/day $65.00/Bbl – $71.00/Bbl
        NGLs (C2 – Ethane)
        January 2019 — March 2019 Swap 900 Bbls/day $14.123/Bbl
        NGLs (C3 – Propane)
        January 2019 — March 2019 Swap 600 Bbls/day $35.165/Bbl
        January 2019 — June 2019 Swap 75 Bbls/day $42.00/Bbl
        NGLs (NC4 – Butane)
        January 2019 — March 2019 Swap 200 Bbls/day $38.63/Bbl
        NGLs (C5 – Pentane)
        January 2019 — December 2019 Swap 100 Bbls/day $65.10/Bbl
        January 2019 — December 2019 Swap 100 Bbls/day $65.31/Bbl

        Guidance

        The Company’s capital budget for 2019 is a range of $30 million to $60 million, depending on commodity prices. The table below sets forth our production and operating costs and expenses guidance for 2019, anticipating a capital budget of $30 million funded primarily through cash flows from operations. The eventual results of our strategic and deleveraging efforts may have a substantial impact on the Company’s ability to achieve the guidance set forth below.

        2019 Guidance
        Capital Expenditures (in millions) $30
        Production:
        Oil (MBbls) 925 — 975
        NGLs (MBbls) 1,250 — 1,350
        Gas (MMcf) 8,650 — 8,750
        Total (MBoe) 3,600 — 3,800
        Cash operating costs (per Boe):
        Lease operating $5.00 — 6.00
        Production and ad valorem taxes 8.5% of oil and gas revenues
        Cash general and administrative $4.50 — 5.50
        Non-cash operating costs (per Boe):
        Non-cash general and administrative $0.75 — 1.25
        Exploration $0.25 — 0.75
        Depletion, depreciation and amortization $15.00 — 17.00

        As further discussed below under “Forward-Looking and Cautionary Statements,” our guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control. In addition, our 2019 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and natural gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

        Conference Call Information and Summary Presentation

        The Company will host a conference call on Tuesday, March 19, 2019, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2018 financial and operational results. Those wishing to listen to the conference call, may do so by visiting the Events page under the Investor Relations section of the Company’s website, www.approachresources.com, or by phone:

        Dial in: (844) 884-9950 / Conference ID: 6089010
        International Dial In: (661) 378-9660
        A replay of the call will be available on the Company’s website or by dialing:
        Dial in: (855) 859-2056 / Passcode: 6089010

        In addition, a fourth quarter and full-year 2018 summary presentation will be available on the Company’s website.

        About Approach Resources

        Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and natural gas reserves in the Midland Basin of the greater Permian Basin in West Texas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

        This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include expectations of anticipated financial and operating results. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. These assumptions, risks and uncertainties include, but are not limited to, our ability to comply with the covenants in our revolving credit facility, our leverage negatively affecting a redetermination under our credit facility, oil, NGL and natural gas prices, our ability to obtain financing to fund our long-term forecasted capital budget, and our ability to access capital markets. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on assumptions, risks and uncertainties related to the Company is available in the Company’s SEC filings, including our Annual Report on Form 10-K. The Company’s SEC filings are also available on the Company’s website at www.approachresources.com . Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

        UNAUDITED RESULTS OF OPERATIONS
        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Revenues (in thousands):
        Oil $ 13,874 $ 14,082 $ 66,398 $ 52,748
        NGLs 6,730 8,530 14,033 27,702
        Gas 1,771 5,805 33,604 24,899
        Total oil, NGLs and gas sales 22,375 28,417 114,035 105,349
        Net cash payment on derivative settlements (364 ) (2,878 ) (7,050 ) (4,359 )
        Total oil, NGLs and gas sales including derivative impact $ 22,011 $ 25,539 $ 106,985 $ 100,990
        Production:
        Oil (MBbls) 251 270 1,070 1,107
        NGLs (MBbls) 338 377 1,443 1,486
        Gas (MMcf) 2,240 2,498 9,408 9,829
        Total (MBoe) 963 1,064 4,082 4,232
        Total (MBoe/d) 10.5 11.6 11.2 11.6
        Average prices:
        Oil (per Bbl) $ 55.23 $ 52.09 $ 62.04 $ 47.63
        NGLs (per Bbl) 19.91 22.61 23.28 18.64
        Gas (per Mcf) 0.79 2.32 1.49 2.53
        Total (per Boe) $ 23.24 $ 26.71 $ 27.94 $ 24.89
        Net cash payment on derivative settlements (per Boe) (0.38 ) (2.70 ) (1.73 ) (1.03 )
        Total including derivative impact (per Boe) $ 22.86 $ 24.01 $ 26.21 $ 23.86
        Costs and expenses (per Boe):
        Lease operating $ 5.21 $ 4.77 $ 5.18 $ 4.23
        Production and ad valorem taxes 1.80 2.09 2.19 2.04
        Exploration 0.43 0.38 0.10 0.86
        General and administrative (1) 2.80 5.16 5.13 5.75
        Depletion, depreciation and amortization 14.96 15.20 15.05 16.66
        (1) Below is a summary of general and administrative expense:
        General and administrative – cash component $ 1.84 $ 4.09 $ 4.38 $ 4.65
        General and administrative – noncash component (share-based compensation) 0.96 1.07 0.75 1.10
        APPROACH RESOURCES INC. AND SUBSIDIARIES
        UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
        (In thousands, except shares and per-share amounts)
        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        REVENUES:
        Oil, NGLs and gas sales $ 22,375 $ 28,417 $ 114,035 $ 105,349
        EXPENSES:
        Lease operating 5,013 5,076 21,129 17,902
        Production and ad valorem taxes 1,734 2,219 8,923 8,644
        Exploration 411 406 420 3,657
        General and administrative 2,693 5,491 20,922 24,333
        Depletion, depreciation and amortization 14,403 16,173 61,432 70,521
        Total expenses 24,254 29,365 112,826 125,057
        OPERATING (LOSS) INCOME (1,879 ) (948 ) 1,209 (19,708 )
        OTHER:
        Interest expense, net (6,595 ) (5,370 ) (25,117 ) (21,053 )
        Gain on debt extinguishment 5,053
        Commodity derivative gain (loss) 9,747 (1,377 ) (321 ) (262 )
        Other income (expense) 1 (29 ) 32
        INCOME (LOSS) BEFORE INCOME TAX (BENEFIT) PROVISION 1,274 (7,695 ) (24,258 ) (35,938 )
        INCOME TAX (BENEFIT) PROVISION:
        Current (66 ) (66 ) (66 )
        Deferred 472 (53,512 ) (4,281 ) 76,487
        NET INCOME (LOSS) $ 868 $ 45,817 $ (19,911 ) $ (112,359 )
        EARNINGS (LOSS) PER SHARE:
        Basic $ 0.01 $ 0.51 $ (0.21 ) $ (1.35 )
        Diluted $ 0.01 $ 0.51 $ (0.21 ) $ (1.35 )
        WEIGHTED AVERAGE SHARES OUTSTANDING:
        Basic 94,739,926 90,114,659 94,581,294 83,404,104
        Diluted 94,736,926 90,114,659 94,581,294 83,404,104
        UNAUDITED SELECTED FINANCIAL DATA
        Unaudited Consolidated Balance Sheet Data December 31,
        (in thousands) 2018 2017
        Cash and cash equivalents $ 22 $ 21
        Other current assets 16,203 16,679
        Property and equipment, net, successful efforts method 1,068,422 1,082,876
        Total assets $ 1,084,647 $ 1,099,576
        Current liabilities $ 21,077 $ 25,067
        Long-term debt (1) 384,993 373,460
        Deferred income taxes 77,821 82,102
        Other long-term liabilities 11,511 11,531
        Stockholders’ equity 589,245 607,416
        Total liabilities and stockholders’ equity $ 1,084,647 $ 1,099,576

        (1) Long-term debt at December 31, 2018, is comprised of $85.2 million in 7% senior notes due 2021 and $301.5 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $0.7 million and $1 million, respectively. Long-term debt at December 31, 2017, is comprised of $85.2 million in 7% senior notes due 2021 and $291 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $1.1 million and $1.7 million, respectively.

        Unaudited Consolidated Cash Flow Data Year Ended December 31,
        (in thousands) 2018 2017
        Net cash provided by (used in):
        Operating activities $ 34,744 $ 37,454
        Investing activities (42,764 ) (52,409 )
        Financing activities 8,021 14,955

        Supplemental Non-GAAP Financial and Other Measures

        This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures and on the Non-GAAP Financial Information page under the Financial Reporting subsection of the Investor Relations section of our website at www.approachresources.com.

        Adjusted Net Loss

        This release contains the non-GAAP financial measures adjusted net loss and adjusted net loss per diluted share, which excludes (1) non-cash fair value gain commodity derivatives, (2) gain on debt extinguishment, (3) write-off of deferred tax assets, (4) acquisition related costs, (5) tax benefit related to federal tax law change, and (6) related income tax effect on adjustments and other discrete tax items. The amounts included in the calculation of adjusted net loss and adjusted net loss per diluted share below were computed in accordance with GAAP. We believe adjusted net loss and adjusted net loss per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below provides a reconciliation of adjusted net loss to net income (loss) for the three and twelve months ended December 31, 2018 and 2017 (in thousands, except per-share amounts).

        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Net income (loss) $ 868 $ 45,817 $ (19,911 ) $ (112,359 )
        Adjustments for certain items:
        Non-cash fair value (gain) loss on derivatives (10,111 ) (1,500 ) (6,729 ) (4,097 )
        Gain on debt extinguishment (5,053 )
        Write-off of deferred tax assets 139,090
        Acquisition related costs 110 110
        Tax benefit related to change in federal tax law (51,939 ) (51,939 )
        Tax effect and other discrete tax items (1) 2,318 1,446 1,677 4,443
        Adjusted net loss $ (6,925 ) $ (6,066 ) $ (24,963 ) $ (29,805 )
        Adjusted net loss per diluted share $ (0.07 ) $ (0.07 ) $ (0.26 ) $ (0.36 )

        (1) The estimated income tax impacts on adjustments to net income (loss) are computed based upon a statutory rate of 21% and 35%, applicable to 2018 and 2017, respectively. Additionally, this includes the tax impact of a tax shortfall related to share-based compensation of $0.2 million, and $1 million for the three months ended December 31, 2018, and December 31, 2017, respectively; and $0.3 million and $1.3 million for the years ended December 31, 2018, and December 31, 2017, respectively.

        EBITDAX

        We define EBITDAX as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) non-cash fair value (gain) loss on derivatives, (5) gain on debt extinguishment, (6) interest expense, net, and (7) income tax provision (benefit). EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income (loss) because of its wide acceptance by the investment community as a financial indicator of a company’s ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below provides a reconciliation of EBITDAX to net income (loss) for the three and twelve months ended December 31, 2018 and 2017 (in thousands).

        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Net income (loss) $ 868 $ 45,817 $ (19,911 ) $ (112,359 )
        Exploration 411 406 420 3,657
        Depletion, depreciation and amortization 14,403 16,173 61,432 70,521
        Share-based compensation 923 1,138 3,047 4,656
        Non-cash fair value (gain) loss on derivatives (10,111 ) (1,500 ) (6,729 ) (4,097 )
        Gain on debt extinguishment (5,053 )
        Interest expense, net 6,595 5,370 25,117 21,053
        Income tax provision (benefit) 406 (53,512 ) (4,347 ) 76,421
        EBITDAX $ 13,495 $ 13,892 $ 59,029 $ 54,799

        Unhedged Cash Margin and Cash Operating Expenses

        We define unhedged cash margin as revenue, less cash operating expenses. We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, and (3) share-based compensation expense. Unhedged cash margin and cash operating expenses are not measures of operating income or cash flows as determined by GAAP. The amounts included in the calculations of unhedged cash margin and cash operating expenses were computed in accordance with GAAP. Unhedged cash margin and cash operating expenses are presented herein and reconciled to the GAAP measures of revenue and operating expenses. We use unhedged cash margin and cash operating expenses as an indicator of the Company’s profitability and ability to manage its operating income and cash flows. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below provides a reconciliation of unhedged cash margin and cash operating expenses to revenues and operating expenses for the three and twelve months ended December 31, 2018 and 2017 (in thousands, except per-Boe amounts).

        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Revenues $ 22,375 $ 28,417 $ 114,035 $ 105,349
        Production (Mboe) 963 1,064 4,082 4,232
        Average realized price (per Boe) $ 23.24 $ 26.71 $ 27.94 $ 24.89
        Operating expenses $ 24,254 $ 29,365 $ 112,826 $ 125,057
        Exploration (411 ) (406 ) (420 ) (3,657 )
        Depletion, depreciation and amortization (14,403 ) (16,173 ) (61,432 ) (70,521 )
        Share-based compensation (923 ) (1,138 ) (3,047 ) (4,656 )
        Cash operating expenses $ 8,517 $ 11,648 $ 47,927 $ 46,223
        Cash operating expenses per Boe $ 8.85 $ 10.95 $ 11.75 $ 10.92
        Unhedged cash margin $ 13,858 $ 16,769 $ 66,108 $ 59,126
        Unhedged cash margin per Boe $ 14.39 $ 15.76 $ 16.19 $ 13.97

        PV-10

        The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $761.8 million at December 31, 2018, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and gas, of $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of natural gas price during 2018, adjusted for basis differentials, grade and quality.

        PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.

        The table below reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

        (in millions) December 31, 2018
        PV-10 $ 761.8
        Less income taxes:
        Undiscounted future income taxes (478.2 )
        10% discount factor 376.4
        Future discounted income taxes (101.8 )
        Standardized measure of discounted future net cash flows $ 660

        Liquidity

        Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below summarizes our liquidity at December 31, 2018 and 2017 (in thousands).

        Year Ended December 31,
        2018 2017
        Credit Facility commitments $ 325,000 $ 325,000
        Cash and cash equivalents 22 21
        Long-term debt — Credit Facility (301,500 ) (291,000 )
        Undrawn letters of credit (325 ) (325 )
        Liquidity $ 23,197 $ 33,696

        View source version on businesswire.com: https://www.businesswire.com/news/home/20190318005810/en/

        SOURCE: Approach Resources Inc.

        Sergei Krylov
        Executive Vice President & Chief Financial Officer
        ir@approachresources.com
        817.989.9000

        Copyright Business Wire 2019

        https://www.marketwatch.com/press-release/approach-resources-inc-reports-fourth-quarter-and-full-year-2018-financial-and-operating-results-2019-03-18

    • Frontera Delivers Strong Fourth Quarter and 2018 Results and Replaces 103% of 2018 Produced Reserves

      March 14, 2019

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      March 14, 2019

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    • EOG Resources Reports Fourth Quarter and Full Year 2018 Results and Announces 2019 Capital Program

      March 1, 2019

        • Earns Record Net Income in 2018 and Generates Significant Net Cash from Operating Activities and Free Cash Flow
        • Exceeds Fourth Quarter Crude Oil and NGL Production Target Midpoints
        • Increases Proved Reserves by 16% and Replaces 238% of 2018 Production at Sub-$10 Finding Cost
        • Targets Improved Capital Efficiency, Significant Investment in High-Quality New Drilling Potential and 12-16% U.S. Crude Oil Volume Growth in 2019, Funded with Net Cash from Operating Activities at $50 Oil

        EOG Resources, Inc. (EOG) today reported fourth quarter 2018 net income of $893 million, or $1.54 per share. This compares to fourth quarter 2017 net income of $2.4 billion, or $4.20 per share. For the full year 2018, EOG reported a company record net income of $3.4 billion, or $5.89 per share, compared to $2.6 billion, or $4.46 per share, for the full year 2017. Net cash from operating activities for the fourth quarter and full year 2018 was $2.1 billion and $7.8 billion, respectively.

        Adjusted non-GAAP net income for the fourth quarter 2018 was $718 million, or $1.24 per share, compared to adjusted non-GAAP net income of $401 million, or $0.69 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2018 was $3.2 billion, or $5.54 per share, compared to adjusted non-GAAP net income of $648 million, or $1.12 per share, for the full year 2017. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

        Fourth Quarter and Full Year 2018 Review
        EOG delivered exceptional financial and operating performance in 2018. The company generated record net income and free cash flow, while ending the year with strong improvements in well productivity and additional cost reductions. Total company crude oil volumes grew 19 percent to 399,900 barrels of oil per day (Bopd). Natural gas liquids production increased 31 percent, while natural gas volumes grew 11 percent, contributing to total company production growth of 18 percent.

        In the fourth quarter 2018, EOG exceeded the high end of its target range for U.S. crude oil volumes by producing 430,300 Bopd, an increase of 17 percent compared to the same prior year period. Per-unit operating expenses declined during the fourth quarter 2018 compared to the same prior year period. Lower general and administrative expenses, transportation costs and depreciation, depletion and amortization expenses each contributed to the overall cost reduction.

        EOG generated $2.1 billion of discretionary cash flow and incurred total expenditures of $1.5 billion in the fourth quarter 2018. After considering cash exploration and development expenditures, excluding acquisitions, of $1.3 billion and dividend payments of $127 million, the company generated free cash flow during the fourth quarter of $637 million. For the full year 2018 EOG generated a company record $1.7 billion of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

        “Our goal at EOG is to be one of the best companies in the S&P 500. Our stellar 2018 performance delivered a premium combination of high returns and double-digit production growth while generating record free cash flow,” said William R. “Bill” Thomas, Chairman and Chief Executive Officer. “Our 2018 results show that we can be competitive with the best companies across all sectors, and we remain relentlessly focused on further improving our cost structure and operating performance.”

        2019 Capital Plan
        EOG’s capital plan is custom-designed each year to increase returns and capital efficiencies. In 2019, EOG is allocating more capital to opportunistic, high quality new drilling potential and somewhat less capital to drilling in established areas. The company’s disciplined growth strategy emphasizes generating free cash flow while lowering well costs and per-unit operating expenses and driving improvement in well productivity. Retaining high-quality equipment and crews during the fourth quarter of 2018 positioned the company to further improve efficiencies and returns in 2019.

        EOG expects to grow U.S. crude oil production by 12 to 16 percent, fund capital investment and pay the dividend with net cash from operating activities in 2019 at $50 oil. Exploration and development expenditures for 2019 are expected to range from $6.1 to $6.5 billion, including facilities and gathering, processing and other expenditures, excluding acquisitions and non-cash exchanges.

        EOG expects to complete approximately 740 net wells in 2019 compared to 763 net wells in 2018. Activity will remain focused in EOG’s highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and Bakken. The company’s investment in new potential areas in the United States includes spending for leasing and related infrastructure to drill wells in a number of new prospects in 2019.

        “EOG’s disciplined 2019 capital plan delivers improved capital efficiency and strong high-return growth while making investments in new organic high-quality drilling potential to improve the future performance of the company,” Thomas said. “Our focus on innovation and operational execution, as well as our investment in new drilling potential, will continue to increase the quality of EOG’s premium portfolio. EOG is poised to further improve its position as one of the lowest cost oil producers in the global market, able to create shareholder value through commodity price cycles.”

        Operating Highlights
        EOG completed 262 net wells in the Delaware Basin and increased crude oil production 47% to 126,800 Bopd in 2018. The company made significant progress during 2018 in improving well productivity and reducing well costs. EOG refined spacing and development patterns, reduced drilling days and applied new completion technology designed to lower costs and improve well productivity.

        EOG continues to drive growth and operating efficiencies in its premier South Texas Eagle Ford asset. In 2018, the company grew crude oil production 9% to 171,000 Bopd. Of the 304 net wells completed in 2018, EOG drilled a total of 65 wells with lateral lengths greater than 10,000 feet. These wells included the Slytherin C#3H, which, at 13,500 feet, was a company record in the Eagle Ford.

        EOG’s Powder River Basin and Wyoming DJ Basin activity both contributed to the company’s 2018 crude oil production growth. In the Powder River Basin, the company brought eight wells on line during the fourth quarter targeting the Turner, Mowry and Parkman formations. The company plans to add infrastructure and further delineate the field and test additional targets in 2019 to be positioned to execute a more robust development program in the Niobrara and Mowry in 2020 and beyond. In the Wyoming DJ Basin, EOG generated further cost reductions during 2018 through efficiency improvements in drilling, completion and production operations. The company brought 20 wells to sales in the fourth quarter, all targeting the Codell formation. EOG expects further crude oil production growth from its high rate of return drilling in the DJ Basin in 2019.

        EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window, where it brought five wells on line in the fourth quarter. The company made significant progress in reducing well costs during 2018, and, as a result, has lowered its 2019 well cost target to $7.6 million.

        In the Williston Basin, EOG realized significant operational improvements in 2018. The company drilled 20 net wells with an average treated lateral length of 9,500 feet per well. Efficient drilling performance delivered, on average, an additional 1,000 feet of lateral length per well in 2018 for the same cost as 2017. EOG’s Austin 45-1113H well set a company record in the basin with a spud-to-total depth time of 8.4 days.

        Reserves
        At year-end 2018, total company net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), an increase of 16 percent compared to year-end 2017. Net proved reserve additions from all sources, excluding revisions due to price, replaced 238 percent of EOG’s 2018 production at a finding and development cost of $9.33 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 35 MMBoe and asset divestitures decreased net proved reserves by 11 MMBoe. For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        For the 31st consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.

        Financial Review
        At December 31, 2018, EOG’s total debt outstanding was $6.1 billion for a debt-to-total capitalization ratio of 24 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $4.5 billion for a net debt-to-total capitalization ratio of 19 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        EOG completed its previously announced agreement to divest all of its U.K. operations in the fourth quarter 2018. Proceeds from the U.K. divestment and other asset sales in 2018 totaled $227 million.

        Fourth Quarter 2018 Results Webcast
        Wednesday, February 27, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
        Webcast will be available on EOG 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
        John Wagner  713-571-4404

        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.  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 economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
        • ­ the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
        • ­ the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, 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 costs with respect to such properties;
        • ­ the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;
        • ­ competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
        • ­ the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
        • ­ the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
        • ­ weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage and transportation facilities;
        • ­ the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
        • ­ EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
        • ­ the extent to which EOG is successful in its completion of planned asset dispositions;
        • ­ the extent and effect of any hedging activities engaged in by EOG;
        • ­ the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
        • ­ 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;
        • ­ physical, electronic and cybersecurity breaches; and
        • ­ the other factors described under ITEM 1A, Risk Factors, on pages 13 through 22 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

        In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG’s forward-looking statements. EOG’s forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

        The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include “potential” reserves, “resource potential” and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, 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.

        EOG RESOURCES, INC.

        Financial Report

        (Unaudited; in millions, except per share data)

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Operating Revenues and Other

        $

        4,574.5

        $

        3,340.4

        $

        17,275.4

        $

        11,208.3

        Net Income 

        $

        892.8

        $

        2,430.5

        $

        3,419.0

        $

        2,582.6

        Net Income Per Share 

                Basic

        $

        1.55

        $

        4.22

        $

        5.93

        $

        4.49

                Diluted

        $

        1.54

        $

        4.20

        $

        5.89

        $

        4.46

        Average Number of Common Shares

                Basic

        577.0

        575.4

        576.6

        574.6

                Diluted

        580.3

        579.2

        580.4

        578.7

        Summary Income Statements

        (Unaudited; in thousands, except per share data)

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Operating Revenues and Other

                Crude Oil and Condensate

        $

        2,383,326

        $

        1,929,471

        $

        9,517,440

        $

        6,256,396

                Natural Gas Liquids

        266,037

        249,172

        1,127,510

        729,561

                Natural Gas

        389,213

        246,922

        1,301,537

        921,934

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

        132,095

        (45,032)

        (165,640)

        19,828

                Gathering, Processing and Marketing

        1,331,105

        1,008,385

        5,230,355

        3,298,087

                Gains (Losses) on Asset Dispositions, Net

        79,904

        (65,220)

        174,562

        (99,096)

                Other, Net

        (7,144)

        16,741

        89,635

        81,610

                       Total

        4,574,536

        3,340,439

        17,275,399

        11,208,320

        Operating Expenses

                Lease and Well

        346,442

        281,941

        1,282,678

        1,044,847

                Transportation Costs

        196,095

        191,717

        746,876

        740,352

                Gathering and Processing Costs

        112,396

        43,295

        436,973

        148,775

                Exploration Costs

        33,862

        22,941

        148,999

        145,342

                Dry Hole Costs

        145

        4,532

        5,405

        4,609

                Impairments 

        186,087

        153,442

        347,021

        479,240

                Marketing Costs

        1,349,416

        1,009,566

        5,203,243

        3,330,237

                Depreciation, Depletion and Amortization

        919,963

        881,745

        3,435,408

        3,409,387

                General and Administrative

        116,904

        117,005

        426,969

        434,467

                Taxes Other Than Income

        190,086

        158,343

        772,481

        544,662

                       Total

        3,451,396

        2,864,527

        12,806,053

        10,281,918

        Operating Income 

        1,123,140

        475,912

        4,469,346

        926,402

        Other Income, Net

        21,220

        803

        16,704

        9,152

        Income Before Interest Expense and Income Taxes

        1,144,360

        476,715

        4,486,050

        935,554

        Interest Expense, Net

        56,020

        63,362

        245,052

        274,372

        Income Before Income Taxes

        1,088,340

        413,353

        4,240,998

        661,182

        Income Tax Provision (Benefit)

        195,572

        (2,017,115)

        821,958

        (1,921,397)

        Net Income 

        $

        892,768

        $

        2,430,468

        $

        3,419,040

        $

        2,582,579

        Dividends Declared per Common Share

        $

        0.2200

        $

        0.1675

        $

        0.8100

        $

        0.6700

        EOG RESOURCES, INC.

        Operating Highlights

        (Unaudited)

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017