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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 2020
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 1-8590
mur-20201231_g1.jpg
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware71-0361522
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-20077024
Houston,Texas
(Zip Code)
(Address of principal executive offices)
(281)675-9000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
 Title of each classTrading SymbolName of each exchange on which registered
Common Stock, $1.00 Par ValueMURNew York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  ☒   No  ☐ 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  ☐   No  ☒ 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ☒   No  ☐ 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  ☒   No  ☐ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ☐   No  ☒ 
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (as of June 30, 2020) – $1,206,809,217.
Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2021 was 153,598,625.
Documents incorporated by reference:
Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 12, 2021 have been incorporated by reference in Part III herein.


MURPHY OIL CORPORATION
2020 FORM 10-K
TABLE OF CONTENTS
Page Number
i
Table of Contents
PART I
Item 1. BUSINESS
Summary
Murphy Oil Corporation is a global oil and natural gas exploration and production company, with both Onshore and Offshore operations and properties.  As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.
The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation.  It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses.  In 2013, the U.S. downstream business was separated from Murphy Oil Corporation’s oil and natural gas exploration and production business. For reporting purposes, Murphy’s exploration and production activities are subdivided into three geographic segments, including the United States, Canada, and all other countries.  Additionally, Corporate activities include interest income, interest expense, foreign exchange effects, corporate risk management activities and administrative costs not allocated to the segments.  The Company’s corporate headquarters, originally located in El Dorado, Arkansas, were relocated to Houston, Texas in 2020.
In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 27 through 41, 74 through 76, 102 through 116 and 119 of this Form 10-K report.
Interested parties may obtain the Company’s public disclosures filed with the Securities and Exchange Commission (SEC), including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s Website at www.murphyoilcorp.com.
Exploration and Production
The Company explores for and produces crude oil, natural gas and natural gas liquids worldwide.  The Company’s management team, based in Houston, Texas, directs the Company’s worldwide exploration and production activities.  
During 2020, Murphy’s principal exploration and production activities were conducted in the United States by wholly-owned Murphy Exploration & Production Company – USA (Murphy Expro USA) and its subsidiaries, in Canada by wholly-owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in Australia, Brazil, Brunei, Mexico and Vietnam by wholly-owned Murphy Exploration & Production Company – International (Murphy Expro International) and its subsidiaries.  Murphy’s operations and production in 2020 were in the United States, Canada and Brunei (held for sale).
Unless otherwise indicated, all references to the Company’s offshore U.S. and total oil, natural gas liquids and natural gas production and sales volumes, and proved reserves include a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM; see further details below).
Murphy’s worldwide 2020 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 174,636 barrels of oil equivalent per day, a decrease of 5.9% compared to 2019.
See Management’s Discussion and Analysis of Financial Condition and Results of Operations starting on page 28 for further details on 2020 production and sales volume.
United States 
In the United States, Murphy has production of crude oil, natural gas liquids and natural gas primarily from fields in the Gulf of Mexico and in the Eagle Ford Shale area of South Texas.  The Company produced approximately 101,300 barrels of crude oil and natural gas liquids per day and approximately 94 MMCF of natural gas per day in the U.S. in 2020.  These amounts represented 87.7% of the Company’s total worldwide oil and natural gas liquids and 26.5% of worldwide natural gas production volumes.
Offshore
During 2020, approximately 69% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico, of which approximately 74% was derived from six fields, including Dalmatian, Kodiak, Marmarlard, Neidermeyer, St. Malo and Cascade/Chinook. Total average daily production in the Gulf of Mexico in 2020 was 69,700 barrels of crude oil and natural gas liquids and approximately 66 MMCF of natural gas.  Production in the Gulf of Mexico was significantly impacted by a record breaking hurricane year which resulted in shut-ins and loss of approximately 6.4 MBOED of production in 2020. At December 31, 2020, Murphy had total proved reserves for Gulf of Mexico fields of 144.4 million barrels of oil and natural gas liquids and 127 billion cubic feet of natural gas.   
1
Table of Contents
In 2019, the Company completed a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG), which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets.
In 2018, Murphy Expro USA and Petrobras America Inc. (PAI), a subsidiary of Petróleo Brasileiro S.A., closed a transaction among Murphy, PAI and MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy. The transaction had an effective date of October 1, 2018. MP GOM is now owned 80% by Murphy and 20% by PAI.  Throughout this 10-K report, unless stated otherwise, financial and operational metrics relating to MP GOM include PAI’s 20% noncontrolling interest in MP GOM. 100% of revenues, costs, assets, liabilities and cash flows of MP GOM are fully consolidated in the financial statements.
Below is a summary of Company’s major working interests in the U.S. Gulf of Mexico:
FieldWorking Interest (incl. NCI)Blocks
Operated:
Calliope 1
28.5%Mississippi Canyon 565/609
Cascade
100.0%Walker Ridge 206/250
Chinook
100.0%Walker Ridge 425/469
Cottonwood
100.0%Garden Banks 244
Dalmatian
70.0%DeSoto Canyon Blocks 4/134
Front Runner
62.5%Green Canyon Blocks 338/339/382
Hoffe Park 2
60.0%Mississippi Canyon 122/165/166
Khaleesi 1
34.0%Green Canyon 345/389/390/434
Marmalard
24.4%Mississippi Canyon 255/299/300
Marmalard East
64.6%Mississippi Canyon 301
Medusa
60.0%Mississippi Canyon Blocks 538/582
Mormont 1
34.0%Green Canyon 478
Nearly Headless Nick
26.84%Mississippi Canyon 387
Neidermeyer
52.8%Mississippi Canyon 208/209/252
Powerball
75.0%South Timbalier South 231/232
Samurai 1
50.0%Green Canyon 432/388/431/475/476
Son of Bluto II
26.84%Mississippi Canyon 386/431
Thunder Hawk
62.5%Mississippi Canyon Block 734
Non-operated:
Habanero
33.75%Garden Banks 341
Kodiak
54.1%Mississippi Canyon Blocks 727/771
Lucius
11.5%Keathley Canyon 874/875/918/919
St. Malo
25.0%Walker Ridge 633/634/677/678
Tahoe
30.0%Viosca Knoll 783
1 Fields in development phase.
2 Field in appraisal phase.
Onshore
The Company holds rights to approximately 134 thousand gross acres in South Texas in the Eagle Ford Shale unconventional oil and natural gas play. During 2020, approximately 31% of total U.S. hydrocarbon production was produced in the Eagle Ford Shale. Total 2020 production in the Eagle Ford Shale area was 31,608 barrels of oil and liquids per day and approximately 27 MMCF per day of natural gas.  At December 31, 2020, the Company’s proved reserves for the U.S. Onshore business totaled 130.9 million barrels of liquids and 192.5 billion cubic feet of natural gas. 
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Canada 
In Canada, the Company holds working interests in the following: (a) a dry natural gas area at Tupper Montney (100% owned), (b) Kaybob Duvernay (operated), (c) liquids rich Placid Montney (non-operated), and (d) two non-operated offshore assets – the Hibernia and Terra Nova fields offshore Newfoundland in the Jeanne d’Arc Basin.
Onshore
Murphy has approximately 142 thousand gross acres of Tupper Montney mineral rights located in northeast British Columbia. Daily production in 2020 in onshore Canada averaged 9,200 barrels of liquids and approximately 261 MMCF of natural gas.  Total onshore Canada proved liquids and natural gas reserves at December 31, 2020, were approximately 15.4 million barrels and 2.1 trillion cubic feet, respectively. 
The Company currently has a commitment for 483 MMCFD of natural gas processing capacity. In 2016, the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area.  Connected with this sale, the Company entered into a commitment for 285 MMCFD of natural gas processing capacity for minimum monthly payments through 2051.  In 2018, the Company entered into a further commitment, commencing November 2020 for an additional 198 MMCFD processing capacity through November 2040.
The Company holds a 70% operated working interest in Kaybob Duvernay lands and a 30% non-operated working interest in liquids rich Placid Montney lands, both in Alberta.  The Company has approximately 336 thousand gross acres of Kaybob Duvernay and Placid Montney mineral rights.

Offshore
Murphy has a 6.5% working interest in Hibernia Main, a 4.3% working interest in Hibernia South Extension, and a 10.475% working interest at Terra Nova.  Oil production in 2020 was approximately 4,893 barrels of oil per day for Hibernia. During 2020, Terra Nova did not operate as asset integrity work is currently being reviewed and undertaken. Total proved oil reserves at December 31, 2020 were approximately 14.1 million barrels of liquids and 3.7 billion cubic feet of natural gas.
Brunei
The Company has a working interest of 8.051% in Block CA-1 and a 30% working interest in Block CA-2; both assets are currently held for sale.
In CA-1, on November 23, 2017, the governments of Brunei and Malaysia signed a Unitization Framework Agreement (UFA) which resulted in the Jagus East discovery in Block CA-1 forming part of a unitized field with the Gumusut-Kakap (GK) Unit in Malaysia. Following the UFA, on July 4, 2018, a Participation Agreement was signed which finalized the Company’s interest in the Brunei section of the GK Unit.
In CA-2, in December 2014, the governmental authority approved the Gas Holding Area (GHA) for the Kelidang Cluster (KC) development. The consortium is presently carrying out pre-development engineering related to the KC development with the aim to achieve project sanction in 2023.
The CA-1 and CA-2 blocks cover 1.4 million and 157,602 gross acres, respectively.  Four exploration wells were drilled in Block CA-1 and seven exploration wells were drilled in Block CA-2 at the end of 2020.  
Australia

In Australia, the Company holds four offshore exploration permits and serves as operator of three of them.  All of the permits have high quality 3D seismic data available and exploration studies are ongoing.  None of the permits has a drilling commitment and all have options to renew beyond the current expiry dates. The Company is currently reviewing retaining the Australia permits.
Vietnam
The Company holds a 65% working interest in Blocks 144 and 145; and a 40% interest in Block 15-1/05 and Block 15-2/17. The Company is operator of each of the three Production Sharing Contracts (PSCs).
Block 15-1/05 contains the Lac Da Vang (LDV) discovered field and the consortium is progressing pre-development engineering. Declaration of Commerciality was made in January 2019 and the field Outline Development Plan was approved in
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August 2019. The Lac Da Trang (LDT) 1X exploration well, the last remaining commitment of the PSC, was completed in April 2019. The sanction of the LDV development is under review with PetroVietnam.
In Block 15-2/17, the Company is progressing study activity in anticipation of drilling an exploration commitment well by the end of 2022.
In Blocks 144 and 145, the Company acquired 2D seismic for these blocks in 2013 and undertook seabed surveys in 2015 and 2016. The remaining commitment for the acquisition, processing and interpretation of six hundred square kilometers (600 km2) of 3D seismic is tentatively scheduled for 2022.
Mexico 
In March 2017, as part of Mexico’s fourth phase, round one deepwater auction, Murphy was awarded Block 5. Murphy is the operator of the Block with a 40% working interest.  Block 5 is located in the deepwater Salinas Basin covering approximately 640,000 gross acres (2,600 square kilometers), with water depths ranging from 2,300 to 3,500 feet (700 to 1,100 meters).  The initial exploration period for the license is four years and includes a commitment to drill one exploration well which was drilled in 2019. A further exploration well is planned for 2021-2022.
Brazil
The Company holds an interest in 9 blocks in the offshore regions of the Sergipe-Alagoas Basin (SEAL) in Brazil (SEAL-M-351, SEAL-M-428, SEAL-M-430, SEAL-M-501, SEAL-M-503, SEAM-M-505, SEAL-M-573, SEAL-M-575 and SEAL-M-637). ExxonMobil is the operator of the blocks. Murphy has a 20% working interest, ExxonMobil has a 50% working interest and Enauta Energia SA holds a 30% working interest.  
Murphy has also farmed into 3 additional blocks in the Portiguar Basin (POT-M-857, POT-M-863, and POT-M-865) with a 30% working interest; Wintershall Dea is the operator.
Murphy’s total acreage position in Brazil as of December 31, 2020 is approximately 2,452,568 gross acres, offsetting several major Petrobras discoveries. There are no well commitments.
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Proved Reserves
Total proved reserves for crude oil, natural gas liquids and natural gas as of December 31, 2020 are presented in the following table below:
Proved Reserves
All ProductsCrude
Oil		Natural Gas
Liquids
Natural Gas 4
Proved Developed Reserves:(MMBOE)(MMBBL)(BCF)
United States230.3 161.4 25.5 260.2 
Onshore
120.0 74.9 18.6 158.8 
Offshore 1
110.3 86.5 6.9 101.4 
Canada180.5 18.4 3.2 953.6 
Onshore
171.2 9.6 3.2 950.7 
Offshore
9.3 8.8 — 2.9 
Total proved developed reserves 410.8 179.8 28.7 1,213.8 
Proved Undeveloped Reserves:
United States98.2 79.2 9.1 59.3 
Onshore
43.0 30.8 6.5 33.7 
Offshore 2
55.2 48.4 2.6 25.6 
Canada205.9 7.5 0.4 1,187.9 
Onshore
200.5 2.2 0.4 1,187.1 
Offshore
5.4 5.3 — 0.8 
Total proved undeveloped reserves 304.1 86.7 9.5 1,247.2 
Total proved reserves 3
714.9 266.5 38.2 2,461.0 
1 Includes proved developed reserves of 14.2 MMBOE, consisting of 12.7 MMBBL oil, 0.6 MMBBL NGLs, and 5.7 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
2 Includes proved undeveloped reserves of 3.2 MMBOE, consisting of 2.9 MMBBL oil, 0.1 MMBBL NGLs, and 0.8 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
3 Includes proved reserves of 17.4 MMBOE, consisting of 15.6 MMBBL oil, 0.7 MMBBL NGLs, and 6.5 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
4 Includes proved natural gas reserves to be consumed in operations as fuel of 72.0 BCF and 108.8 BCF for the U.S. and Canada, respectively, with 1.6 BCF attributable to the noncontrolling interest in MP GOM.
Murphy Oil’s 2020 total proved reserves and proved undeveloped reserves are reconciled from 2019 as presented in the table below:
(Millions of oil equivalent barrels) 1
Total
Proved 
Reserves		Total Proved
Undeveloped
Reserves
Beginning of year825.0 352.7 
Revisions of previous estimates(194.7)(178.0)
Extensions and discoveries150.3 148.8 
Conversions to proved developed reserves — (17.7)
Sale of properties(1.7)(1.7)
Production(63.9)— 
End of year 2
714.9 304.1 
1 For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.
2 Includes 17.4 MMBOE and 3.2 MMBOE for total proved and proved undeveloped reserves, respectively, attributable to the noncontrolling interest in MP GOM.

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Proved Reserves (Cont’d.)
During 2020, Murphy’s total proved reserves decreased by 110.1 million barrels of oil equivalent (MMBOE).  The decrease in reserves principally relates to less capital allocation over the next five years toward onshore shale production growth resulting in a transfer of 164.7 MMBOE to probable, reduced price resulting in a loss of 41.8 MMBOE and 2020 production of 63.9 MMBOE; partially offset by improved base performance of 30 MMBOE plus extensions and discoveries of 126 MMBOE in Onshore Canada, 16 MMBOE in the Eagle Ford Shale, and 8 MMBOE in Offshore U.S. Gulf of Mexico and east Canada.
Murphy’s total proved undeveloped reserves at December 31, 2020 decreased 48.6 MMBOE from a year earlier.  The proved undeveloped reserves reported in the table as extensions and discoveries during 2020 were predominantly attributable to three areas:  the onshore Canada area of Tupper Montney, the Eagle Ford Shale in South Texas, and the U.S. Gulf of Mexico. Each of these areas had active development work ongoing during the year. The majority of proved undeveloped reserves associated with revisions of previous estimates was the result of reduced capital expenditures in the Eagle Ford Shale over the next five years. The majority of the proved undeveloped reserves migration to the proved developed category are attributable to drilling in the Eagle Ford Shale, Gulf of Mexico, Kaybob Duvernay, and Tupper Montney.
The Company spent approximately $594 million in 2020 to convert proved undeveloped reserves to proved developed reserves.  The Company expects to spend approximately $447 million in 2021, $526 million in 2022 and $314 million in 2023 to move currently undeveloped proved reserves to the developed category.  The anticipated level of spending in 2021 primarily includes drilling and development in the Gulf of Mexico, Eagle Ford Shale and Tupper Montney areas. 
At December 31, 2020, proved reserves are included for several development projects, including oil developments at the Eagle Ford Shale in South Texas; natural gas developments in Tupper Montney; deepwater Gulf of Mexico; and Kaybob Duvernay in onshore Canada. Total proved undeveloped reserves associated with various development projects at December 31, 2020 were approximately 304.1 MMBOE, which represent 43% of the Company’s total proved reserves.
Certain development projects have proved undeveloped reserves that will take more than five years to bring to production.  The Company is currently executing a drilling and completion campaign in Tupper Montney in onshore Canada and operates deepwater fields in the Gulf of Mexico that have six and two undeveloped locations, respectively that exceed this five-year window. Two of the six Tupper Montney PUDs are already online and producing above expectations. Total reserves associated with the eight locations amount to approximately 2.7% of the Company’s total proved reserves at year-end 2020. The development of certain reserves extends beyond five years due to an ongoing drilling campaign that is close to completion and limited well slot availability, thus making it necessary to wait for depletion of other wells prior to initiating further development of these locations.
Murphy Oil’s Reserves Processes and Policies
As per the SEC, proved oil and natural gas reserves are “those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The SEC has defined reasonable certainty for proved reserves, as a “high degree of confidence that the quantities will be recovered.” Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.
Murphy has established both internal and external controls for estimating proved reserves that follow the guidelines set forth by the SEC for oil and natural gas reporting.  Certain qualified technical personnel of Murphy from the various exploration and production business units are responsible for the preparation of proved reserve estimates and these technical representatives provide the necessary information and maintain the data as well as the documentation for all properties.
Proved reserves are then consolidated and reported through the Corporate Reserves group.  Murphy’s General Manager of Corporate Reserves (Reserves Manager) leads the Corporate Reserves group that also includes Corporate reserve engineers and support staff in which all are independent of the Company’s oil and natural gas operational management and technical personnel.  The Reserves Manager joined Murphy in 2018 and has more than 20 years of industry experience.  He has a Bachelor of Science and a Master of Science degree in Petroleum Engineering as well as a Master of Business Administration.  The Reserves Manager is also a licensed Professional Engineer in the State of Texas. The Reserves Manager reports to the Chief Financial Officer and makes annual presentations to the Board of Directors about the Company’s reserves.  The Reserves Manager and the Corporate reserve engineers review and discuss reserves estimates directly with the Company’s technical staff in order to make every effort to ensure compliance with the rules and regulations of the SEC.  The Reserves Manager coordinates and oversees the third-party audits which are performed annually and under Company policy generally target coverage of at least one-third of the barrel oil-equivalent volume of the Company’s proved reserves. 
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Murphy Oil’s Reserves Processes and Policies (Cont’d.)
The estimated proved reserves reported in this Form 10-K are prepared by Murphy’s employees. Internal audits may also be performed by the Reserves Manager and qualified engineering staff from areas of the Company other than the area being audited by third parties. In 2020, 94.8% of the Proved reserves were audited by third-party auditors and they were found to be within the acceptable 10% tolerance by each of the third party firms. Murphy engaged both Ryder Scott Company, L.P. (Ryder Scott) and McDaniel & Associates Consultants Ltd. (McDaniel) to perform a reserves audit of 46.0% and 48.8% of the Company’s total proved reserves, respectively.
Each significant exploration and production business unit also maintains one or more Qualified Reserve Estimators (QRE) on staff.  The QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area.  The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others.  A QRE is professionally qualified to perform these reserves estimates as a result of having sufficient educational background, professional training, and professional experience to enable him or her to exercise prudent professional judgment.  Larger business units of the Company also employ a Regional Reserves Coordinator (RRC) who supervises the local QREs. The RRC is usually a senior QRE who has the primary responsibility for coordinating and submitting reserves information to senior management.
QRE qualification requires a minimum of five years of practical experience in petroleum engineering or petroleum production geology, with at least three years of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.  Murphy provides annual training to all company reserves estimators to ensure SEC requirements associated with reserves estimation and Form 10-K reporting are fulfilled.  The training includes materials provided to each participant that outlines the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserves estimation.
The Company’s QREs maintain files containing pertinent data regarding each significant reservoir.  Each file includes sufficient data to support the calculations or analogies used to develop the values.  Examples of data included in the file, as appropriate, include:  production histories; pertinent drilling and workover histories; bottom hole pressure data; volumetric, material balance, analogy, or other pertinent reserve estimation data; production performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the documentation stating that, in their opinion, the reserves have been calculated, reviewed, documented, and reported in compliance with SEC regulations.  When reserves calculations are completed by technical personnel with the support of the QREs and appropriately reviewed by RRCs, the Corporate reserves engineers and the Reserves Manager, the conclusions are reviewed and approved with the heads of the Company’s exploration and production business units and other senior management on an annual basis.  The Company’s Controller’s department is responsible for preparing and filing reserves schedules within the Form 10-K report.
To ensure accuracy and security of reported reserves, the proved reserves estimates are coordinated in industry-standard software with access controls for approved users.  In addition, Murphy complies with internal controls concerning the various business processes related to reserves. 
More information regarding Murphy’s estimated quantities of proved reserves of crude oil, natural gas liquids, and natural gas for the last three years are presented by geographic area on pages 103 through 110 of this Form 10-K report.  Also, Murphy currently has no oil and natural gas reserves from non-traditional sources.  Murphy has not filed and is not required to file any estimates of its total proved oil or natural gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission.  Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.
Crude oil, condensate and natural gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the three years ended December 31, 2020 are shown on pages 36 through 38 of this Form 10-K report.    
Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page 33 of this Form 10-K report. 
Supplemental disclosures relating to oil and natural gas producing activities are reported on pages 102 through 117 of this Form 10-K report.
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Acreage and Well Count
At December 31, 2020, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table.  Gross acres are those in which all or part of the working interest is owned by Murphy.  Net acres are the portions of the gross acres attributable to Murphy’s interest.
DevelopedUndevelopedTotal
Area (Thousands of acres)
GrossNetGrossNetGrossNet
United States  – Onshore109 97 38 35 147 132 
– Gulf of Mexico37 17 539 264 576 281 
Total United States146 114 577 299 723 413 
Canada – Onshore140 107 364 259 504 366 
– Offshore101 8 28 1 129 9 
Total Canada241 115 392 260 633 375 
Mexico— — 636 254 636 254 
Brazil— — 2,453 568 2,453 568 
Australia— — 4,935 2,505 4,935 2,505 
Brunei— — 1,604 164 1,604 164 
Vietnam— — 7,324 4,571 7,324 4,571 
Spain— — 8 1 8 1 
Totals387 229 17,929 8,622 18,316 8,851 
Certain acreage held by the Company will expire in the next three years. 
Scheduled expirations in 2021 include 116 thousand net acres in Brunei, 35 thousand net acres in onshore Canada and 3 thousand net acres in the Gulf of Mexico.
Acreage currently scheduled to expire in 2022 include 4,521 thousand net acres in Vietnam (which can be retained with sanction of development plan), 47 thousand net acres in Brunei, 46 thousand net acres in the Gulf of Mexico and 22 thousand net acres in onshore Canada.
Scheduled expirations in 2023 include 75 thousand net acres in Brazil, 10 thousand net acres in onshore Canada and 16 thousand net acres in the Gulf of Mexico.
As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly-owned wells.  An “exploratory” well is drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area.  A “development” well is drilled within the proved area of an oil or natural gas reservoir that is known to be productive.
The following table shows the number of oil and natural gas wells producing or capable of producing at December 31, 2020.
Oil WellsNatural Gas Wells
GrossNetGrossNet
Country
United States  – Onshore1,067 888 — — 
– Offshore58 29 20 10 
Total United States1,125 917 20 10 
Canada – Onshore26 14 366 302 
– Offshore52 4 — — 
Total Canada78 18 366 302 
Totals1,203 935 386 312 
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Acreage and Well Count (Cont’d.)
Murphy’s net wells drilled in the last three years are shown in the following table.
United StatesCanadaOtherTotals
ProductiveDryProductiveDryProductiveDryProductiveDry
2020
Exploration— 0.4 0.7 — — — 0.7 0.4 
Development21.5 — 8.9 — — — 30.4 — 
2019
Exploration0.6 — — — — — 0.6 — 
Development84.6 — 18.6 — — — 103.2 — 
2018
Exploration0.5 0.4 — — — — 0.5 0.4 
Development46.6 — 28.1 — — — 74.7 — 
Murphy’s drilling wells in progress at December 31, 2020 are shown in the following table.  The year-end well count includes wells awaiting various completion operations.  
ExplorationDevelopmentTotal
GrossNetGrossNetGrossNet
Country
United States  – Onshore— — 59.0 19.5 59.0 19.5 
– Offshore— — 6.0 1.3 6.0 1.3 
Canada— — — — — — 
Totals— — 65.0 20.8 65.0 20.8 
Discontinued Operations
Malaysia – In July 2019, the Company closed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $985.4 million was recorded as part of discontinued operations on the Consolidated Statement of Operations. The Company has accounted for and reported the Malaysia business as discontinued operations for all periods presented.
Refining and Marketing – The Company decommissioned the Milford Haven refinery units and completed the sale of its remaining downstream assets in the U.K. in 2015 for cash proceeds of $5.5 million.  The Company has accounted for and reported this U.K. downstream business as discontinued operations for all periods presented. In October 2019, the current owner of the former Milford Haven Refinery issued a completion certificate acknowledging the Company had satisfactorily completed all obligations regarding the decommissioning and demolition of the facility’s refinery equipment.    
Environmental, Health and Safety
We are subject to various international, foreign, national, state, provincial and local environmental, health and safety laws and regulations, including related to the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located.
U.S. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). CERCLA and similar state statutes impose joint and several liability, without regard to fault or legality of the conduct, on current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Although CERCLA generally exempts “petroleum” from regulation, in the course of our operations, we may and could generate wastes that may fall within CERCLA’s definition of hazardous substances and may have disposed of these wastes at disposal sites owned and operated by others.
Water discharges. The U.S. Clean Water Act (CWA) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into regulated waters. The U.S. Oil Pollution Act (OPA) imposes certain duties and liabilities on the owner or operator of a facility,
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vessel or pipeline that is a source or that poses the substantial threat of an oil discharge, or the lessee or permittee of the area in which a discharging offshore facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill.
U.S. Bureau of Ocean Energy Management (BOEM) and the U.S. Bureau of Safety and Environmental Enforcement (BSEE) requirements. BOEM and BSEE have regulations applicable to lessees in federal waters that impose various safety, permitting and certification requirements applicable to exploration, development and production activities in the Gulf of Mexico, and also require lessees to have substantial U.S. assets and net worth or post bonds or other acceptable financial assurance that the regulatory obligations will be met.
In April 2016, the BSEE enacted broad regulatory changes related to Gulf of Mexico well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. These changes are known broadly as the Well Control Rule, and amendments to this rule were enacted in May 2019. Compliance is required over the next several years.
In July 2016, BOEM issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures BOEM used to determine a lessee’s ability to carry out decommissioning obligations for activities on the Outer Continental Shelf (OCS), including the Gulf of Mexico. This revised policy became effective in September 2016 and instituted new criteria by which the BOEM will evaluate the financial strength and reliability of lessees and operators active on the OCS. If the BOEM determines under the revised policy that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance. In January 2017 BOEM extended the implementation timeline for the NTL by six months for properties which have co-lessees, and in February 2017 BOEM withdrew sole liability orders issued in December 2016 to allow time for the new administration to review the financial assurance program for decommissioning.
Air emissions and climate change. The U.S. Clean Air Act (CAA) and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and other authorization requirements. Since 2009, the U.S. Environmental Protection Agency (EPA) has been monitoring and regulating GHG emissions, including carbon dioxide and methane, from certain sources in the oil and natural gas sector due to their association with climate change. An international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021.
Murphy is currently required to report GHG emissions from its U.S. operations in the Gulf of Mexico and onshore in south Texas and in its Canadian onshore business in British Columbia and Alberta. In British Columbia and Alberta, Murphy is subject to a carbon tax on the purchase or use of many carbon-based fuels. Additionally, starting in 2017, a carbon tax began to be applied to certain operations in Alberta. Any limitation on, or further regulation of, greenhouse gases, including through a cap and trade system, technology mandate, emissions tax, or expanded reporting requirements, could restrict the Company’s operations, curtail demand for hydrocarbons generally and/or impose increased costs to operate and maintain facilities, install pollution emission controls and administer and manage emissions trading programs.
Endangered and threatened species. The U.S. Endangered Species Act was established to protect endangered and threatened species. If a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, and marine mammals under the Marine Mammal Protection Act.
Safety. The Company is subject to the requirements of the U.S. Occupational Safety and Health Act (OSHA) and comparable foreign and state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information regarding hazardous materials used or produced in Murphy’s operations be maintained and provided to employees, state and local government authorities and citizens. In Canada, the Company is subject to Federal OH&S Legislation, the provincially-administered Occupational Health and Safety Act (Alberta), the Workers Compensation Act (British Columbia), and WHMIS - the Workplace Hazardous Materials Information System.





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Human Capital Resources
Employees
At Murphy, we believe in providing energy that empowers people, and that is what our 675 employees do every day. As of December 31, 2020, we had 425 office-based employees and 250 field employees, all of whom are guided by our mission, vision, values and behaviors. Together with the Executive Management Team, the Vice President of Human Resources and Administration is responsible for developing and executing our human capital management strategy. This includes the attraction, recruitment, development and engagement of talent to deliver on our strategy and the design of employee compensation, health and welfare benefits, and talent programs. We focus on the following factors in order to implement and develop our human capital strategy:
•Employee Compensation Programs
•Employee Performance and Feedback
•Talent Development and Training
•Health and Welfare Benefits
•Diversity, Equity and Inclusion
Employee Compensation Programs
Our purpose, to empower people includes tying a portion of our employees pay to performance in a variety of ways, including incentive compensation and merit-based bonus programs, while maintaining the best interest of shareholders. We benchmark for market practices, and regularly review our compensation against the market to ensure it remains competitive to attract and retain the best talent. Our current practices align our employees’ compensation with the interests of our shareholders, and support our focus on cash flow generation, capital returns and environmental stewardship. For further detail on the Company’s compensation framework please see Exhibit 99.1 on Form 8-K filed on February 8, 2021 and the Compensation Discussion and Analysis section of the forthcoming Proxy Statement relating to the Annual Meeting of Stockholders on May 12, 2021.
Employee Performance and Feedback
We are committed to efforts to enhance our employees’ professional growth and development through feedback that utilizes our internal performance management system (Murphy Performance Management - MPM). The purpose of Murphy’s MPM process is to show our commitment to the development of all employees and to better align rewards with Company and individual performance. The goals of the MPM process are the following:
•Drive behavior to align with the Company’s mission, vision, values and behaviors
•Develop employee capabilities through effective feedback and coaching
•Maintain a process that is consistent throughout the organization to measure employee performance and are tied to Company and Shareholder interests
All employees’ performance is evaluated annually through self-assessments that are reviewed in discussions with supervisors. Employees’ performance is evaluated on various key performance indicators set annually, including behaviors that support our mission, vision, values and an assessment conducted by the employees’ direct supervisor.
Talent Development and Training
Employees are able to participate in continuous training and development, with the goal of equipping them for success and providing increased opportunities for growth at Murphy. Through our digital platform, My Murphy Learning, employees can access self-directed courses, external articles, and videos that cover topics such as business, technology, and productivity. Also, we are able to administer mandatory compliance training for our employees through My Murphy Learning, with a 100% utilization rate. Further, we strive to empower our leadership, so we sponsor several programs to address career advancement for emerging leaders and executives. Plus, we provide a tuition reimbursement program for those who choose to acquire additional knowledge to increase their effectiveness in their present position or to prepare the employee for advancement.
We encourage employee engagement and solicit feedback through internal surveys and our employee driven Ambassador program to gain insights into workplace experiences. Employees are provided opportunities to raise suggestions and collaborate with leadership to improve programs and increase alignment.
To ensure that our human capital investment and development programs are effective, we track voluntary turnover. This data is shared on a regular basis with our leadership team, who use it in addition to other pertinent data to develop our human capital strategy. In 2020, our voluntary employee turnover was 6%.
Health and Welfare Benefits
We believe that doing our part to aid in maintaining the health and welfare of our employees is a critical element in Murphy achieving success. As such, we provide our employees and their families with a comprehensive set of benefits that are competitive and aligned to Murphy’s mission, vision, values and behaviors. We also believe that the wellbeing of our employees is enhanced when they can give back to their local communities or charities either through the company “Impact –
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Murphy Makes a Difference” program or on their own and receive a company match for donations and additional vacation days to volunteer time.
In addition, we offer an Employee Assistance Program (EAP) that provides confidential assistance to employees and their immediate family members for mental and physical wellbeing, as well as legal and financial issues. We also maintain an Ethics Hotline that is available to all our employees to report, anonymously if desired, any matter of concern. Communications to the hotline, which is facilitated by an independent third party, are routed to appropriate functions, Human Resources, Law or Compliance, for investigation and resolution.
Response to COVID-19
We have taken a proactive approach to addressing the COVID-19 pandemic’s impact on our employees. We have implemented a mitigation and response program which is being led by our Incident Management Team (IMT), leveraging the advice and recommendations of infectious disease experts, establishing safety protocols for field workers and work from home procedures for office employees. In order to protect the health of our employees, we have balanced a carefully considered return to office policy that complies with local guidelines.
During, the pandemic, we wanted to reinforce aligning our culture with our mission, vision, values and behaviors, so we have significantly increased leadership updates and management outreach in conjunction with CEO sponsored quarterly Town Hall events.
Diversity, Equity and Inclusion
We are committed to fostering work environments that value diversity, equity, and inclusion. This commitment includes providing equal access to, and participation in, programs and services without regard to race, creed, religion, color, national origin, disability, sex (including pregnancy), sexual orientation, gender identity, veteran status, age or stereotypes or assumptions based thereon. We welcome our employees’ differences, experiences and beliefs, and we are investing in a more productive, engaged, diverse and inclusive workforce. During 2020, under the leadership of our Vice President Human Resources and Administration, we expanded the responsibilities of our Director Talent Development to include the strategic management and planning for diversity and inclusion programs within the company, as well as enhancing our understanding, and providing mandatory training and development for all employees. In addition, our Board has had a woman representative for over 30 years, and currently includes two women directors. Our Nominating and Governance Committee is actively focused on issues of diversity and inclusion as part of its overall mandate. Also, our Board expanded the focus of the Health, Safety and Environment Committee to include Corporate Responsibility.
Women Representation (US and International)
2020
Executive and Senior Level Managers12 %
First- and Mid-Level Managers17 %
Professionals34 %
Other (Administrative Support and Field)7 %
Total21 %
Minorities 1 Representation (US-Based Only)
2020
Executive and Senior Level Managers12 %
First- and Mid-Level Managers23 %
Professionals33 %
Other (Administrative Support and Field)31 %
Total30 %
1 As defined by the U.S. Equal Employment Opportunity Commission (EEOC).
We believe that it is important we attract employees with diverse backgrounds where we operate and are focusing on increasing the number of women and minorities in our workforce ensuring a vibrant talent pipeline. We acknowledge these efforts were hindered in 2020 by office closures and the reduction in force, both caused by the OPEC+ oil price disruptions and the ongoing COVID-19 pandemic (discussed further in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page 28), and we look to ongoing improvement in our diversity representation.


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Website Access to SEC Reports
Murphy Oil’s internet Website address is http://www.murphyoilcorp.com. The information contained on the Company’s Website is not part of this report on Form 10-K.
The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on Murphy’s Website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC.  You may also access these reports at the SEC’s Website at http://www.sec.gov.
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Item 1A. RISK FACTORS
Price Risk Factors
Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.
Among the most significant variable factors impacting the Company’s results of operations are the sales prices for crude oil and natural gas that it produces. Many of the factors influencing prices of crude oil and natural gas are beyond our control. These factors include:
•the occurrence or threat of epidemics or pandemics, such as the recent outbreak of coronavirus disease 2019 (COVID-19), or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;
•worldwide and domestic supplies of and demand for crude oil, natural gas liquids and natural gas;
•the ability of the members of OPEC and certain non-OPEC members, for example, certain major suppliers such as Russia and Saudi Arabia, to agree to and maintain production levels;
•the production levels of non-OPEC countries, including, amongst others, production levels in the shale plays in the United States;
•the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
•political instability or armed conflict in oil and natural gas producing regions;
•changes in weather patterns and climate;
•natural disasters such as hurricanes and tornadoes;
•the price, availability and the demand for and of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;
•the effect of conservation efforts;
•technological advances affecting energy consumption and energy supply;
•domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
•general economic conditions worldwide.
The global economic downturn triggered by the COVID-19 pandemic (discussed below) has impacted demand, and hence has applied further downward pressure on hydrocarbon (most notably oil) energy prices. The longer the COVID-19 pandemic continues, including prolonged government restrictions on businesses and reduced activity of consumers, the longer the downward pressure will be applied.
In the first quarter of 2020, certain major global suppliers announced supply increases in oil which contributed to the lower global commodity prices. In the first quarter of 2020, certain countries also announced unexpected price discounts of $6 to $8 per barrel to global customers. In the second quarter of 2020, the OPEC+ group of producers agreed to cut output by 9.7 million barrels of oil per day (MMBLD) in May and June 2020, which was later extended through the end of July 2020. Cuts of 7.7 MMBLD were made from August and December 2020. Subsequent to year end, production cuts have been scaled back to 7.2 MMBLD in January 2021 and 7.1 MMBLD for February and March. However, outside of the OPEC+ agreement, Saudi Arabia unilaterally implemented an additional 1.0 MMBLD cut in February and March 2021.
West Texas Intermediate (WTI) crude oil prices averaged approximately $39 in 2020, compared to $57 in 2019, $65 in 2018, and $51 per barrel in 2017. The closing price for WTI at the end of 2020 was approximately $47 per barrel, reflecting a 21% reduction from the price at the end of 2019. As of close on February 25, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $61.38 and $56.51 per barrel, respectively. The current futures forward curve indicates that prices may continue at or near current prices for an extended time. Certain U.S. and Canadian crude oils are priced from oil indices other than WTI, and these indices are influenced by different supply and demand forces than those that affect WTI prices. The most common crude oil indices used to price the Company’s crude include WTI Houston (MEH), Heavy Louisiana Sweet (HLS), Mars and Brent.
The average New York Mercantile Exchange (NYMEX) natural gas sales price was $1.99 per million British Thermal Units (MMBTU) in 2020, compared to $2.52 in 2019, $3.12 per MMBTU in 2018, and $2.96 per MMBTU in 2017. The closing price for NYMEX natural gas as of December 31, 2020, was $2.58 per MMBTU. The Company also has exposure to the Canadian
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benchmark natural gas price, AECO, which averaged US$1.66 per MMBTU in 2020.  The closing price for AECO as of December 31, 2020 was US$2.03 per MMBTU. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 47 and certain variable netback contracts providing exposure to Malin, Dawn and other locations.
Lower prices may materially and adversely affect our results of operations, cash flows and financial condition, and this trend could continue into 2021. Lower oil and natural gas prices could reduce the amount of oil and natural gas that the Company can economically produce, resulting in a reduction in the proved oil and natural gas reserves we could recognize, which could impact the recoverability and carrying value of our assets. The Company cannot predict how changes in the sales prices of oil and natural gas will affect the results of operations in future periods. The Company has hedged a portion of its exposure to the effects of changing prices of crude oil and natural gas by selling forwards, swaps and other forms of derivative contracts. The Company markets a portion of Canadian natural gas production to locations other than AECO and through physical forward sales.
See Note M – Financial Instruments and Risk Management for additional information on the derivative instruments used to manage certain risks related to commodity prices.
Murphy could face long-term challenges to the fossil fuels business model reducing demand and price for hydrocarbon fuels.
As environmental and social trends change towards less carbon intensive energy sources, Murphy’s business model may come under more pressure from changing global demands for non-fossil fuel energy sources. As part of Murphy’s strategy review process, the Company reviews hydrocarbon demand forecasts and assesses the impact on its business model and plans. The Company also has significant natural gas reserves which emit lower carbon compared to oil and liquids.

The issue of climate change has caused considerable attention to be directed towards initiatives to reduce global greenhouse gas emissions. An international climate agreement (the “Paris Agreement”) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021. It is possible that the Paris Agreement, and other such initiatives, including foreign, federal and state rules or regulations related to greenhouse gas emissions and climate change, may reduce the demand for crude oil and natural gas globally. In addition to regulatory risk, other market and social initiatives such as public and private initiatives that aim to subsidize the development of non-fossil fuel energy sources, may reduce the competitiveness of carbon-based fuels, such as oil and gas. While the magnitude of any reduction in hydrocarbon demand is difficult to predict, such a development could adversely impact the Company and other companies engaged in the exploration and production business. With or without renewable-energy subsidies, the unknown pace and strength of technological advancement of non-fossil-fuel energy sources creates uncertainty about the timing and pace of effects on our business model. The Company continually monitors the global climate change agenda initiatives and plans accordingly based on its assessment of such initiatives on its business.
Low oil and natural gas prices may adversely affect the Company’s operations in several ways in the future.
Lower oil and natural gas prices adversely affect the Company in several ways:
•Lower sales value for the Company’s oil and natural gas production reduces cash flows and net income.
•Lower cash flows may cause the Company to reduce its capital expenditure program, thereby potentially restricting its ability to grow production and add proved reserves.
•Lower oil and natural gas prices could lead to impairment charges in future periods, therefore reducing net income.
•Reductions in oil and natural gas prices could lead to reductions in the Company’s proved reserves in future years. Low prices could make a portion of the Company’s proved reserves uneconomic, which in turn could lead to the removal of certain of the Company’s year-end reported proved oil reserves in future periods. These reserve reductions could be significant.
•In order to manage the potential volatility of cash flows and credit requirements, we maintain appropriate bank credit facilities.  Inability to access, renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity.
•Lower prices for oil and natural gas could cause the Company to lower its dividend because of lower cash flows.
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Certain of these effects are further discussed in risk factors that follow.
Murphy’s commodity price risk management may limit the Company’s ability to fully benefit from potential future price increases for oil and natural gas.
The Company, from time to time, enters into various contracts to protect its cash flows against lower oil and natural gas prices. Because of these contracts, if the prices for oil and natural gas increase in future periods, the Company will not fully benefit from the price improvement on all production.
Operational Risk Factors
Murphy operates in highly competitive environments which could adversely affect it in many ways, including its profitability, cash flows and its ability to grow.
Murphy operates in the oil and natural gas industry and experiences competition from other oil and natural gas companies, which include state-owned foreign oil companies, major integrated oil companies, private equity investors and independent producers of oil and natural gas. Many of the state-owned and major integrated oil companies and some of the independent producers that compete with the Company have substantially greater resources than Murphy.
In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy competes, among other things, for valuable acreage positions, exploration licenses, drilling equipment and talent.
Exploration drilling results can significantly affect the Company’s operating results.
The Company drills exploratory wells which subjects its exploration and production operating results to exposure to dry holes expense, which may have adverse effects on, and create volatility for, the Company’s results of operations. In response to lower oil prices in recent years, the Company has reduced its exploration program from pre-2015 levels and currently plans to participate in approximately three to five exploration wells per year. In 2020, the Company reduced its exploration drilling plans further in response to external factors and participated in two unsuccessful non-operated exploration wells in the U.S. Gulf of Mexico. The Company has budgeted $73 million for its 2021 exploration program, which includes one non-operated well in the U.S. Gulf of Mexico, up to two non-operated wells in Brazil, and one non-operated well in Brunei; subject to rig availability/timing.
If Murphy cannot replace its oil and natural gas reserves, it may not be able to sustain or grow its business.
Murphy continually depletes its oil and natural gas reserves as production occurs. To sustain and grow its business, the Company must successfully replace the oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserves additions and production. The Company does this by obtaining rights to explore for, develop and produce hydrocarbons in prospective areas. In addition, it must find, develop and produce and/or acquire reserves at a competitive cost to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and production business, therefore, is dependent on its ability to find (and/or acquire), develop and produce oil and natural gas reserves at costs that are less than the realized sales price for these products.
Acquisitions – In 2019, the Company, completed a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG), whereby the Company acquired 26 blocks in the Mississippi Canyon and Green Canyon areas of the Gulf of Mexico.  In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. In 2018, the Company entered into a transaction among Murphy, PAI and MP Gulf of Mexico, LLC (MP GOM), whereby the Company through its interest in MP GOM acquired an 80% interest in PAI Gulf of Mexico producing Assets (Cascade, Chinook, Lucius, St. Malo, Cottonwood, South Marsh Island, Northwestern, and South Hadrian fields) and its interests in exploration blocks in the U.S. Gulf of Mexico to MP GOM.
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Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.
Proved reserves of crude oil, natural gas liquids (NGL) and natural gas included in this report on pages 102 through 110 have been prepared according to the Securities and Exchange (SEC) guidelines by qualified Company personnel or qualified independent engineers based on an unweighted average of crude oil, NGL and natural gas prices in effect at the beginning of each month of the respective year as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground oil and natural gas reservoirs. Estimates of economically recoverable crude oil, NGL and natural gas reserves and future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods. In 2020, 94.8% of the Proved reserves were audited by third-party auditors.
Murphy’s actual future oil and natural gas production may vary substantially from its reported quantity of proved reserves due to a number of factors, including:
•Oil and natural gas prices which are materially different from prices used to compute proved reserves
•Operating and/or capital costs which are materially different from those assumed to compute proved reserves
•Future reservoir performance which is materially different from models used to compute proved reserves, and
•Governmental regulations or actions which materially impact operations of a field.
The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2020, and including noncontrolling interests, approximately 33% of the Company’s crude oil and condensate proved reserves, 25% of natural gas liquids proved reserves and 51% of natural gas proved reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers.
The discounted future net revenues from our proved reserves as reported on pages 115 and 116 should not be considered as the market value of the reserves attributable to our properties. As required by generally accepted accounting principles (GAAP), the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year. Actual future prices and costs may be materially higher or lower than those used in the reserves computations.
In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on our cost of capital, the risks associated with our business and the risk associated with the industry in general.
Murphy is sometimes reliant on joint venture partners for operating assets, and/or funding development projects and operations.
Certain of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its revenue generating properties. During 2020, approximately 22% of the Company’s total production was at fields operated by others, while at December 31, 2020, approximately 13% of the Company’s total proved reserves were at fields operated by others.
Additionally, the Company relies on the availability of transportation and processing facilities that are often owned and operated by others. These third-party systems and facilities may not always be available to the Company, and if available, may not be available at a price that is acceptable to the Company.
Some of Murphy’s development projects entail significant capital expenditures and have long development cycle times. As a result, the Company’s partners must be able to fund their share of investment costs through the development cycle, through cash flow from operations, external credit facilities, or other sources, including financing arrangements. Murphy’s partners are also susceptible to certain of the risk factors noted herein, including, but not limited to, commodity price, fiscal regime changes, government project approval delays, regulatory changes, credit downgrades and regional conflict. If one or more of these factors negatively impacts a project partners’ cash flows or ability to obtain adequate financing, it could result in a delay or cancellation of a project, resulting in a reduction of the Company’s reserves and production, which negatively impacts the timing and receipt of planned cash flows and expected profitability.
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Murphy’s business is subject to operational hazards, physical security risks and risks normally associated with the exploration and production of oil and natural gas.
The Company operates in urban and remote, and sometimes inhospitable, areas around the world. The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes (and other forms of severe weather), mechanical equipment failures, industrial accidents, fires, explosions, acts of war, civil unrest, piracy and acts of terrorism could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, personal injury, (including death), and property damages for which the Company could be deemed to be liable and which could subject the Company to substantial fines and/or claims for punitive damages. This risk extends to actions and operational hazards of other operators in the industry, which may also impact the Company.
The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes and tropical storms. Many of the Company’s offshore fields are in the U.S. Gulf of Mexico, where hurricanes and tropical storms can lead to shutdowns and damages. The U.S. hurricane season runs from June through November. Moreover, it should be noted that scientists have predicted that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that increase significant weather events, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Although the Company maintains insurance for such risks as described elsewhere in this Form 10-K report, due to policy deductibles and possible coverage limits, weather-related risks are not fully insured.  
Murphy is subject to numerous environmental, health and safety laws and regulations, and such existing and any potential future laws and regulations may result in material liabilities and costs.
The Company’s operations are subject to various international, foreign, national, state, and provincial, and local environmental, health and safety laws and regulations, including related to the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations are subject to frequent change and have tended to become stricter over time. They can impose operational controls and/or siting constraints on our business and can result in additional capital and operating expenditures.
Murphy also could be subject to strict liability for environmental contamination in various jurisdictions where we operate, including with respect to its current or former properties, operations and waste disposal sites, or those of its predecessors. Contamination has been identified at some locations and the Company has been required, and in the future may be required, to investigate, remove or remediate previously disposed wastes; or otherwise clean up contaminated soil, surface water or groundwater, address spills and leaks from pipelines and production equipment, and perform remedial plugging operations. In addition to significant investigation and remediation costs, such matters can result in fines and also give rise to third-party claims for personal injury and property or other environmental damage.
It is possible in the future certain regulatory bodies such as the Railroad Commission of Texas may enact regulation that bans or reduces flaring for US Onshore operations. Compliance with such regulations could result in capital investment which would reduce the Company’s net cash flows and profitability.
The Company’s onshore North America oil and natural gas production is dependent on a technique known as hydraulic fracturing whereby water, sand and certain chemicals are injected into deep oil and natural gas bearing reservoirs in North America. This process occurs thousands of feet below the surface and creates fractures in the rock formation within the reservoir which enhances migration of oil and natural gas to the wellbore. The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada. In June 2011, the State of Texas adopted a law requiring public disclosure of certain information regarding the components used in the hydraulic fracturing process. The Provinces of British Columbia and Alberta have also issued regulations related to various aspects of hydraulic fracturing activities under their jurisdictions. It is possible that the states, the U.S., Canadian provinces and certain municipalities adopt further laws or regulations which could render the process unlawful, less effective or drive up its costs. If any such action is taken in the future, the Company’s production levels could be adversely affected, or its costs of drilling and completion could be increased.  Once new laws and/or regulations have been enacted and adopted, the costs of compliance are appraised.
Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas. These risks include underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or groundwater contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or groundwater contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third-party claims alleging damages, which could adversely affect
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the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water; the wastewater from oil and natural gas operations is often disposed of through underground injection. Certain increased seismic activities have been linked to underground water injection. Any diminished access to water for use in the hydraulic fracturing process, any inability to properly dispose of wastewater, or any further restrictions placed on wastewater, could curtail the Company’s operations or otherwise result in operational delays or increased costs.
In April 2016, BSEE enacted broad regulatory changes related to Gulf of Mexico well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. These changes are known broadly as the Well Control Rule, and amendments to this rule were enacted in May 2019. Compliance is required over the next several years. Some provisions remain for which BSEE future enforcement actions are unclear, so risk of impact leading to increased future cost on the Company’s Gulf of Mexico operations remains.
In July 2016, BOEM issued an updated Notice to Lessees and Operators (NTL) providing details on revised procedures BOEM used to determine a lessee’s ability to carry out decommissioning obligations for activities on the Outer Continental Shelf (OCS), including the Gulf of Mexico. This revised policy became effective in September 2016 and instituted new criteria by which the BOEM will evaluate the financial strength and reliability of lessees and operators active on the OCS. If the BOEM determines under the revised policy that a company does not have the financial ability to meet its decommissioning and other obligations, that company will be required to post additional financial security as assurance. In January 2017 BOEM extended the implementation timeline for the NTL by six months for properties which have co-lessees, and in February 2017 BOEM withdrew sole liability orders issued in December 2016 to allow time for the new administration to review the financial assurance program for decommissioning. Although the Company believes a potential new BOEM policy could lead to increased costs for its Gulf of Mexico operations, it does not currently believe that the impact will be material to its operations in the Gulf of Mexico.
In the future, BOEM and/or BSEE, may impose new and more stringent offshore operating regulations which may adversely affect the Company’s operations.
On January 21, 2021 the Company (along with all operators in the industry) was given notice that the Department of Interior is for 60 days suspending authority for normal-course issuance of permits for fossil fuel development on federal lands. Following this notice, the Department of Interior has continued to approve permits and Murphy has not experienced a delay in project approvals. An extension or permanency of this suspension could impact the options available to Murphy for future development, reserves available for production and hence future cash flows and profitability. In the event leasing delays or cancellations alter Murphy’s plans in the Gulf of Mexico, the company is able to re-focus activities and allocate capital to other areas. The company does not hold any onshore federal lands in the U.S. Further, on January 27, 2021, the President signed an Executive Order announcing the pause of new oil and natural gas leasing on public lands and offshore waters while undertaking a review of the federal oil and gas program. The pause does not impact existing operations or permits for valid, existing leases, which are continuing to be reviewed and approved. See Risk Factors – General Risk Factors – Murphy’s operations and earnings have been and will continue to be affected by domestic and worldwide political developments.
Financial Risk Factors
Capital financing may not always be available to fund Murphy’s activities; and interest rates could impact cash flows.
Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production.  Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding requirements may not always coincide, and the levels of cash flow generated by operations may not fully cover capital funding requirements, especially in periods of low commodity prices. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company periodically renews these financing arrangements based on foreseeable financing needs or as they expire. In November 2018, the Company entered into a $1.6 billion revolving credit facility (the “RCF”). The RCF is a senior unsecured guaranteed facility and will expire in November 2023.
Amounts drawn under the RCF may bear interest in relation to LIBOR, depending on our selection of rates. In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of 2021. Financial industry working groups are developing replacement rates, such as the Secured Overnight Financing Rate (SOFR) discussed below, and methodologies to transition existing agreements that depend on LIBOR as a reference rate; however, we can provide no assurance that market-accepted rates and transition methodologies will be available and finalized at the time of LIBOR cessation. If clear market standards and transition methodologies have not developed by the time LIBOR becomes unavailable, we may have difficulty reaching agreement on acceptable replacement rates under the RCF. If we are unable to negotiate replacement rates, on favorable terms, it could have a material adverse effect on our earnings and cash flows.
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In 2018, the Alternative Reference Rates Committee (ARRC), a group of private-market participants convened by the Federal Reserve Board and the New York Fed, recommended an alternative to LIBOR, the Secured Overnight Financing Rate (SOFR). The publication of SOFR began in April 2018, and, therefore, it has a limited history. In addition, the future performance of SOFR cannot be predicted based on the limited historical performance. SOFR is fundamentally different from USD LIBOR for two key reasons. First, SOFR is a secured rate, while LIBOR is an unsecured rate. Second, SOFR is an overnight rate, while USD LIBOR represents interbank funding over different maturities. As a result, there can be no assurance that SOFR will perform in the same way as LIBOR would have at any time, including, without limitation, as a result of changes in interest and yield rates in the market, market volatility or global or regional economic, financial, political, regulatory, judicial or other events.
In November 2019, the Company issued $550 million of new notes that bear interest at a rate of 5.875% and mature on December 1, 2027 and repurchased and canceled $239.7 million of the Company’s 4.00% notes due 2022 and $281.6 million of the Company’s 4.45% notes due 2022 (originally issued as 3.70% notes due 2022) during November and December 2019.
The Company’s ability to obtain additional financing is also affected by the Company’s debt credit ratings and competition for available debt financing.  A ratings downgrade could materially and adversely impact the Company’s ability to access debt markets, increase the borrowing cost under the Company’s credit facility and the cost of future debt, and potentially require the Company to post additional letters of credit or other forms of collateral for certain obligations.
Further, changes in economic environments and investors’ view of risk of the exploration and production industry could adversely impact interest rates. This could result in higher interest costs on capital funding lowering net income and cash-flows. Murphy partially manages this risk through borrowing at fixed rates where-ever possible; however, rates determined when refinancing or new capital is required are partly determined through factors outside of Murphy’s control, such as centrally (federal government) set interest rates and investors’ view of the exploration and production industry.
See Note H – Financing Arrangements and Debt for information regarding the Company’s outstanding debt and other commitments as of December 31, 2020 and the terms associated therewith.
Murphy’s operations could be adversely affected by changes in foreign exchange rates.
The Company’s worldwide operational scope exposes it to risks associated with foreign currencies. Most of the Company’s business is transacted in U.S. dollars, and therefore the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes. However, the Canadian dollar is the functional currency for all Canadian operations. This exposure to currencies other than the U.S. dollar functional currency can lead to impacts on consolidated financial results from foreign currency translation. On occasions, the Canadian business may hold assets or incur liabilities denominated in a currency which is not Canadian dollars which could lead to exposure to foreign exchange rate fluctuations. See also Note M – Financial Instruments and Risk Management in the Notes to Consolidated Financial Statements for additional information on derivative contracts.
The costs and funding requirements related to the Company’s retirement plans are affected by several factors.
A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.
Murphy has limited control over supply chain costs.
The Company often experiences pressure on its operating and capital expenditures in periods of strong crude oil and natural gas prices because an increase in exploration and production activities due to high oil and natural gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and natural gas industry. The increase in oil prices in 2017 and 2018 (compared to 2015 to 2016) led to some upward inflation pressure in oil field goods and service costs during those years. In 2019 the cost of goods and services in the oil and natural gas industry were approximately in line with 2018. In 2020, following the reduction in oil prices (mainly as a result of the COVID-19 pandemic), the Company observed reductions in the costs for oil and natural gas goods and services.
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The Company is exposed to credit risks associated with (i) sales of certain of its products to customers, (ii) joint venture partners and (iii) other counterparties.
Murphy is exposed to credit risk in three principle areas:
• Accounts receivable credit risk from selling its produced commodity to customers;
• Joint venture partners related to certain oil and natural gas properties operated by the Company. These joint venture partners may not be able to meet their financial obligation to pay for their share of capital and operating costs as they become due; and
• Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices
To mitigate these risks the Company:
• Actively monitors the credit worthiness of all its customers, joint venture partners, and forward commodity hedge counterparties;
• Given the inherent credit risks in a cyclical commodity price business, the Company has increased the focus on its review of joint venture partners, the magnitude of potential exposure, and planning suitable actions should a joint venture partner fail to pay its share of capital and operating expenditures.
The inability of a purchaser of the Company’s produced commodity, a joint venture partner of the Company, or counterparty in a forward price commodity hedge to meet their respective payment obligations to the Company could have an adverse effect on Murphy’s future earnings and cash flows.
General Risk Factors
We face various risks related to health epidemics, pandemics and similar outbreaks, which may have material adverse effects on our business, financial position, results of operations and/or cash flows.
We face various risks related to health epidemics, pandemics and similar outbreaks, including the global outbreak of COVID-19. In 2020 the continued spread of COVID-19 has led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which has applied downward pressure on global commodity prices. See Risk Factors – Price Risk Factors – Volatility in the global prices of crude oil, natural gas liquids and natural gas can significantly affect the Company’s operating results.
If significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, facility closures or other restrictions in connection with the COVID-19 pandemic, our operations will likely be impacted and decrease our ability to produce, oil, natural gas liquids and natural gas. We may be unable to perform fully on our contracts and our costs may increase as a result of the COVID-19 outbreak. These cost increases may not be fully recoverable or adequately covered by insurance.
It is possible that the continued spread of COVID-19 could also further cause disruption in our supply chain; cause delay, or limit the ability of vendors and customers to perform, including in making timely payments to us; and cause other unpredictable events. The impact of COVID-19 has impacted capital markets, which may increase the cost of capital and adversely impact access to capital. The impact on capital markets may also impact our customers financial position and recoverability of our receivables from sales to customers.
We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address responsibly this global pandemic. We continue to monitor the situation, to assess further possible implications to our business, supply chain and customers, and to take actions in an effort to mitigate adverse consequences. The Company initiated an aggressive cost and capital expenditures reduction program in response to the lower commodity price as a result of weaker demand caused by the COVID-19 pandemic.
We cannot at this time predict the impact of the COVID-19 pandemic, but it could have a material adverse effect on our business, financial position, results of operations and/or cash flows. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.
Murphy’s Information Technology environment may be exposed to cyber threats.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct exploration, development, and production activities. We are no exception to this trend. As a company, we depend on these technologies to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, internal and external communication, and conduct many other business activities.
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Maintaining the security of our technology and preventing breaches is critical to our business operation. We rely on our information systems to protect and secure intellectual property, strategic plans, customer information, and personally identifiable information, such as employee information.
A successful or undetected cyberattack has the potential to halt business operations, impair our reputation, weaken our competitive advantage, and / or adversely impact our financial condition. Given the increasing global threats from cybercrime, the Company’s approach to mitigate cybersecurity risk focuses on recurrent internal and external cyber risk assessments, physical and digital asset protection, eradicating security vulnerabilities via preventative and detective measures, and security awareness training.
The Company’s effort to reduce information systems risk extends beyond company personnel and assets. Specifically, where we engage third party providers, the Company includes contract provisions requiring vendors to comply with our security policies, standards and controls, immediately notify us of any actual or suspected information security breaches, and jointly perform risk assessments. As the sophistication of cyber threats continues to evolve, we may be required to dedicate additional resources to continue to modify or enhance our security measures, or to investigate and remediate any vulnerabilities to cyber-attacks.
Murphy’s operations and earnings have been and will continue to be affected by domestic and worldwide political developments.
Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the market of crude oil and natural gas produced in their countries through such actions as changing fiscal regimes (including corporate income tax rates), setting prices, determining rates of production, and controlling who may buy and sell the production.
Murphy is exposed to regulation, legislation and policies enacted by the federal government. As an example, following the election and inauguration of President Biden in January 2021, the U.S. Secretary of the Interior issued Order No. 3395 on January 20, 2021. This order, among other things, placed a 60 day moratorium on oil and gas leases, lease amendments and extension, and drilling permits on federal lands and offshore waters. Following this notice, the Department of Interior has continued to approve permits and Murphy has not experienced a delay in project approvals. An extension or permanency of this suspension could impact the options available to Murphy for future development, reserves available for production and hence future cash flows and profitability. In the event leasing delays or cancellations alter Murphy’s plans in the Gulf of Mexico, the Company believes it will be able to re-focus activities and allocate capital to other areas. The Company does not hold any onshore federal lands in the U.S.
In addition, the Biden administration has taken a number of actions that may result in stricter environmental, health and safety standards applicable to our operations and those of the oil and gas industry more generally. The Biden Administration issued the “Executive Order on Tackling the Climate Crisis at Home and Abroad” on January 27, 2021. This executive order directed the Secretary of the Interior to halt indefinitely new oil and natural gas leases on federal lands and offshore waters pending completion of a review by the Secretary of the Interior of federal oil and gas permitting and leasing practices in light of the Biden administration’s concerns regarding the impact of these activities on the environment and climate. In addition, the Executive Order, among other things, establishes climate conditions as an essential element of U.S. foreign policy; establishes a White House office and a climate task force to coordinate and implement the Biden Administration’s domestic climate change agenda; directs federal agencies to procure carbon pollution-free electricity and zero-emission vehicles; eliminate fossil fuel subsidies as consistent with applicable law; identifies a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050; and commits to a goal of conserving at least 30% of federal lands and oceans by 2030. Separately, President Biden signed another executive order on January 20, 2021, titled “Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis”, which among other things calls for a review of regulations and other executive actions promulgated, issued or adopted during the prior Presidential administration to assess whether they are, in the view of the current Presidential Administration, sufficiently protective of public health and the environment, including with respect to climate change, and consistent with science. The order also specifically calls for consideration of new regulations regarding methane emissions in the oil and gas sector, reassessment of decisions made by the prior administration limiting the size of certain national monuments, limitations on oil and gas exploration and production in the Arctic Refuge, incorporation of the impact of GHG emissions (known as the “social cost of carbon”) in decision making by federal agencies and revoking the permit for the Keystone XL pipeline.
The pause does not impact existing operations or permits for valid, existing leases, which are continuing to be reviewed and approved. However, these actions and any future changes to applicable environmental, health and safety, regulatory and legal requirements promulgated by the current Presidential administration and Congress may restrict our access to additional acreage and new leases in the U.S. Gulf of Mexico or lead to limitations or delays on our ability to secure additional permits to drill and develop our acreage and leases or otherwise lead to limitations on the scope of our operations, or may lead to increases to our
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compliance costs. The potential impacts these changes on our future consolidated financial condition, results of operations or cash flows cannot be predicted.
As of December 31, 2020, none of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada. Prices and availability of crude oil, natural gas and refined products could be influenced by political factors and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include expropriation, tax changes, royalty increases, redefinition of international boundaries, preferential and discriminatory awarding of oil and natural gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Governments could also initiate regulations concerning matters such as currency fluctuations, currency conversion, protection and remediation of the environment, and concerns over the possibility of global warming caused by the production and use of hydrocarbon energy.
A number of non-governmental entities routinely attempt to influence industry members and government energy policy in an effort to limit industry activities, such as hydrocarbon production, drilling and hydraulic fracturing with the desire to minimize the emission of greenhouse gases such as carbon dioxide, which may harm air quality, and to restrict hydrocarbon spills, which may harm land and/or groundwater.
Additionally, because of the numerous countries in which the Company operates, certain other risks exist, including the application of the U.S. Foreign Corrupt Practices Act, the Canada Corruption of Foreign Officials Act, the Brazil Clean Companies Act, the Mexico General Law of the National Anti-Corruption System, and other similar anti-corruption compliance statutes.
It is not possible to predict the actions of governments and hence the impact on Murphy’s future operations and earnings.
Murphy’s insurance may not be adequate to offset costs associated with certain events and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.
Murphy maintains insurance against certain, but not all, hazards that could arise from its operations. The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $500 million per occurrence and in the annual aggregate. Generally, this insurance covers various types of third-party claims related to personal injury, death and property damage, including claims arising from “sudden and accidental” pollution events. The Company also maintains insurance coverage for property damage and well control with an additional limit of $400 million per occurrence ($875 million for Gulf of Mexico claims), all or part of which could apply to certain sudden and accidental pollution events. These policies have deductibles ranging from $10 million to $25 million. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.
Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.
The Company or certain of its consolidated subsidiaries are involved in numerous legal proceedings, including lawsuits for alleged personal injuries, property damages and other business-related matters. Certain of these claims may take many years to resolve through court and arbitration proceedings or negotiated settlements. In the opinion of management and based upon currently known facts and circumstances, the currently pending legal proceedings are not expected, individually or in the aggregate, to have a material adverse effect upon the Company’s operations or financial condition.
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Item 1B. UNRESOLVED STAFF COMMENTS
The Company had no unresolved comments from the staff of the U.S. Securities and Exchange Commission as of December 31, 2020.
Item 2. PROPERTIES
Descriptions of the Company’s oil and natural gas properties are included in Item 1 of this Form 10-K report beginning on page 1.  Information required by the Securities Exchange Act Industry Guide No. 2 can be found in the Supplemental Oil and Gas Information section of this Annual Report on Form 10-K on pages 102 to 117 and in Note G – Property, Plant, and Equipment beginning on page 74.
Item 3. LEGAL PROCEEDINGS
Discussion of the Company’s legal proceedings are included in Note S – Environmental and Other Contingencies beginning on page 96.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
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Information about our Executive Officers
Present corporate office, length of service in office and age at February 1, 2021 of each of the Company’s executive officers are reported in the following listing.  Executive officers are elected annually, but may be removed from office at any time by the Board of Directors.
Roger W. Jenkins – Age 59; President and Chief Executive Officer since 2013.  Mr. Jenkins served as Chief Operating Officer from 2012 to 2013. 
David R. Looney – Age 64; Executive Vice President and Chief Financial Officer since 2018.
Eric M. Hambly – Age 46; Executive Vice President, Operations since 2020. Mr. Hambly served as Executive Vice President, Onshore from 2018 to 2020 and Senior Vice President, U.S. Onshore of Murphy Exploration & Production Company from 2016 to 2018. 
E. Ted Botner – Age 56; Senior Vice President, General Counsel and Corporate Secretary since 2020. Mr. Botner was Vice President, Law and Corporate Secretary from 2015 to 2020 and Manager, Law and Corporate Secretary from 2013 to 2015.
Thomas J. Mireles – Age 48; Senior Vice President, Technical Services (Health, Safety and Environment, Sustainability, Information Technology and Supply Chain) since 2018. Mr. Mireles also served as the Senior Vice President, Eastern Hemisphere of Murphy Exploration & Production Company from 2016 to 2018.
John B. Gardner – Age 52; Vice President and Treasurer since 2015.  Mr. Gardner served as Treasurer from 2013 to 2015.
Christopher D. Hulse – Age 42, Vice President and Controller since 2017. Mr. Hulse was Vice President, Finance, Onshore from 2015 to 2017.
Maria A. Martinez – Age 46; Vice President, Human Resources and Administration since 2018. Ms. Martinez was Vice President, Human Resources of Murphy Exploration & Production Company from 2013 to 2018.
Louis W. Utsch – Age 55; Vice President, Tax since 2018.

Kelly L. Whitley – Age 55; Vice President, Investor Relations and Communications since 2015.  
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PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol.  There were 2,379 stockholders of record as of December 31, 2020.  Information on dividends per share by quarter for 2020 and 2019 are reported on page 118 of this Form 10-K report.
SHAREHOLDER RETURN PERFORMANCE PRESENTATION
The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2015 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), and the Company’s peer group. This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference. The companies in the peer group included:
Apache CorporationDevon Energy CorporationRange Resources Corporation
Cabot Oil & Gas CorporationOvintiv Inc.SM Energy Company
Chesapeake Energy CorporationHess CorporationSouthwestern Energy Company
Cimarex Energy Co.Marathon Oil CorporationWhiting Petroleum Corporation
CNX Resources CorporationMatador Resources Company
mur-20201231_g2.jpg
201520162017201820192020
Murphy Oil Corporation
100 146 151 118 140 66 
Peer Group
100 148 125 82 83 59 
S&P 500 Index
100 112 136 130 171 203 
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Item 6. SELECTED FINANCIAL DATA
The following table contains selected financial data which highlight certain trends in Murphy’s financial condition and results of operations for the last five years. The income statement data for the last three years excludes Malaysia as the Malaysia operations were classified as discontinued operations effective January 1, 2019. See Note E – Assets Held for Sale and Discontinued Operations and Note G – Property, Plant, and Equipment for more information regarding the results of operations and the sale of Malaysia.
(Thousands of dollars except per share data)
Results of Operations for the Year
20202019201820172016
Revenue from sales to customers
$1,751,709 2,817,111 1,806,473 1,300,464 1,862,891 
Net cash provided by continuing operations
802,708 1,489,105 749,395 613,351 600,795 
Income (loss) from continuing operations
(1,255,294)188,815 169,138 (553,015)(273,943)
Net income (loss) attributable to Murphy
(1,148,777)1,149,732 411,094 (311,789)(275,970)
Cash dividends – diluted
95,989 163,669 173,044 172,565 206,635 
Per Common share – diluted
Income (loss) from continuing operations
(7.43)0.52 0.92 (3.21)(1.59)
Net income (loss) attributable to Murphy
(7.48)6.98 2.36 (1.81)(1.60)
Average common shares outstanding (thousands) – diluted
153,507 164,812 174,209 172,524 172,173 
Cash dividends per Common share
$0.625 1.00 1.00 1.00 1.20 
Capital Expenditures for the Year 1
Continuing operations
Exploration and production
$813,300 $2,683,200 1,818,800 942,500 789,721 
Corporate and other
13,300 15,000 22,700 10,300 21,740 
826,600 2,698,200 1,841,500 952,800 811,461 
Discontinued operations
— 64,400 145,800 22,891 — 
$826,600 2,762,600 1,987,300 975,691 811,461 
Financial Condition at December 31
 
 
 
 
 
Current ratio
1.40 1.03 1.04 1.64 1.04 
Working capital (deficit)
$283,971 31,538 33,756 537,396 56,751 
Net property, plant and equipment
8,269,038 9,969,743 8,432,133 8,220,031 8,316,188 
Total assets
10,620,852 11,718,504 11,052,587 9,860,942 10,295,860 
Long-term debt 2
2,988,067 2,803,381 3,109,318 2,906,520 2,422,750 
Murphy shareholders’ equity
4,214,337 5,467,460 4,829,299 4,620,191 4,916,679 
Per share
27.44 35.75 27.91 26.77 28.55 
Long-term debt – percent of capital employed 3  
41.5 33.9 39.2 38.6 33.0 
Stockholder and Employee Data at December 31
Common shares outstanding (thousands)
153,599 152,935 173,059 172,573 172,202 
Number of stockholders of record
2,379 2,265 2,324 2,506 2,588 
1 Capital expenditures include accruals for incurred but unpaid capital activities, while property additions and dry holes in the Statements of Cash Flows are cash-based capital expenditures and do not include capital accruals and geological, geophysical and certain other exploration expenses that are not eligible for capitalization under oil and natural gas accounting rules. 2019 includes $1,261.1 million for proved property acquisitions, primarily related to the LLOG transaction. 2018 includes $794.6 million capital expenditures in relation to the MP GOM transaction.
2 Long-term debt includes non-current capital lease obligations.
3 Long-term debt – percent of capital employed is calculated as total long-term debt at the balance sheet date divided by the sum of total long-term debt plus total Murphy shareholders’ equity at that date.
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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Murphy Oil Corporation is a worldwide oil and natural gas exploration and production company.  A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.
In 2020 the continued spread of coronavirus disease 2019 (COVID-19) has led to significant disruption in the global economy and an associated weakness in demand for crude oil which has resulted in lower commodity prices in 2020 versus 2019. Commodity prices at the end of the first quarter and all of the second quarter were exceptionally impacted. In the first quarter of 2020, certain major global suppliers of crude oil announced supply increases which resulted in a contribution to the lower global commodity prices in the first quarter, shortly followed by exceptional demand reduction from the COVID-19 pandemic. In the second quarter of 2020, the OPEC+ group of oil producing countries agreed to supply restrictions which helped support the oil price in the latter part of the second quarter and through the year end. Nevertheless, oil prices during 2020 remained below average 2019 prices.
In response to the COVID-19 pandemic and reduced commodity prices, the Company reduced 2020 capital expenditures significantly from the original plan of $1.4 billion to $1.5 billion to $712 million (adjusted for comparability to exclude NCI and Kings Quay expenditures). The Company also executed a cost reduction plan for both future direct operational expenditures and general and administrative costs, including closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas (see Note W – Restructuring Charges). The Company is closely monitoring the impact of lower commodity prices on its current and future financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note H – Financing Arrangements and Debt). Also see the Company’s response to COVID-19 as discussed in more detail in the Risk Factors starting on page 14.  
Significant Company operating and financial highlights during 2020 were as follows:
•Preserved liquidity of $1.7 billion, including $310.6 million of cash as of December 31, 2020 and $1.4 billion available on an unsecured revolving credit facility
•Realized $272.0 million as a result of commodity price risk management (forward sale fixed swaps) activities
•Maintained capital discipline with full year accrued capital expenditures of $712.1 million, excluding noncontrolling interest ($21.7 million) and King’s Quay Floating Production System (FPS) of $92.8 million (which is held for sale at the end of 2020)
•Decreased full year Selling, general and administrative costs by 40% from 2019, as a result of a Company wide restructuring
•Produced 174,636 barrels of oil equivalent (BOE) per day (163,617 excluding noncontrolling interest, NCI)
Throughout this section, the term, ‘excluding noncontrolling interest’ or ‘excluding NCI’ refers to amounts attributable to Murphy. Unless noted, amounts include noncontrolling interest.
Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids (NGL) and natural gas in the United States, Gulf of Mexico and Canada and then selling these products to customers.  The Company’s revenue is affected by the prices of crude oil, natural gas and NGL.  In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, depreciation of capital expenditures, and expenses related to exploration, administration, and for capital borrowed from lending institutions and note holders.
Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company.  In 2020, liquids from continuing operations represented 64% of total hydrocarbons produced on an energy equivalent basis.  In 2021, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%.  If the prices for crude oil and natural gas are lower in 2021 or beyond, this will have an unfavorable impact on the Company’s operating profits.  The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.
Oil prices weakened in 2020 compared to the 2019 period. The sales price of a barrel of West Texas Intermediate (WTI) crude oil averaged $39.40 in 2020, $57.03 in 2019, and $64.77 in 2018.  The WTI index decreased approximately 31% over the prior year as a result of decreased demand during the global downturn triggered by the COVID-19 pandemic (see Risk Factors).
The most common crude oil indices used to price the Company’s crude include WTI Houston (MEH), Heavy Louisiana Sweet (HLS), Mars and Brent.
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The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $1.99 in 2020, $2.52 in 2019 and 3.12 in 2018. The 2020 NYMEX natural gas price was lower compared to the 2019 price. On an energy equivalent basis, the market continued to discount North American natural gas and NGLs compared to crude oil in 2020.  Natural gas prices in North America in 2021 have thus far been above those in the comparable period in 2020.
Results of Operations
Murphy Oil’s results of operations, with associated diluted earnings per share (EPS), for the last three years are presented in the following table.
Years Ended December 31,
(Millions of dollars, except EPS)
202020192018
(Loss) income from continuing operations before income taxes$(1,549.0)203.5 43.0 
Net (loss) income attributable to Murphy(1,148.8)1,149.7 411.1 
Diluted EPS
(7.48)6.98 2.36 
(Loss) income from continuing operations attributable to Murphy(1,141.6)85.2 160.7 
Diluted EPS
(7.43)0.52 0.92 
Loss (income) from discontinued operations(7.2)1,064.5 250.3 
Diluted EPS
(0.05)6.46 1.44 
For the year ended December 31, 2020, the Company produced 175 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations.  The Company invested $826.6 million in capital expenditures (on a value of work done basis) in the year ended December 31, 2020, which included $21.7 million attributable to noncontrolling interest and $92.8 million to fund the development of the King’s Quay FPS. The Company reported net loss from continuing operations of $1,255.3 million (which includes post tax impairment charges of $854.2 million and loss attributable to noncontrolling interest of $113.7 million) for the year ended December 31, 2020.
For the year ended December 31, 2019, the Company produced 186 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $2.7 billion in capital expenditures (on a value of work done basis) for the year ended December 31, 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations of $188.8 million (which includes income attributable to noncontrolling interest of $103.6 million) for the year ended December 31, 2019.
Other key performance metrics
The Company uses other operational performance and income metrics to review operational performance. The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management uses EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America. Also presented below is adjusted EBITDA per barrel of oil equivalent sold. Management uses EBITDA per barrel of oil equivalent sold to evaluate the Company’s profitability of one barrel of oil equivalent sold in the period. Adjusted EBITDA per barrel of oil equivalent sold is a non-GAAP financial metric.









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Other key performance metrics (Cont’d.)
Year Ended December 31,
(Millions of dollars, except per barrel of oil equivalents sold)
202020192018
Net (loss) income attributable to Murphy (GAAP)$(1,148.8)1,149.7 411.1 
Income tax expense (benefit)(293.7)14.7 (126.1)
Interest expense, net169.4 219.3 180.4 
Depreciation, depletion and amortization expense 1
932.6 1,076.5 770.6 
EBITDA attributable to Murphy (Non-GAAP)(340.5)2,460.2 1,236.0 
Impairment of assets ¹1,072.5 — 20.0 
Mark-to-market loss (gain) on crude oil derivative contracts69.3 33.4 (33.9)
Restructuring expenses50.0 — — 
Accretion of asset retirement obligations42.1 40.5 27.1 
Unutilized rig charges16.0 — — 
Mark-to-market loss (gain) on contingent consideration(13.8)8.7 (4.8)
Inventory loss8.3 — — 
Discontinued operations (income) loss7.2 (1,064.5)(250.3)
Retirement obligation (gains) losses ¹(2.8)— — 
Seal insurance proceeds(1.7)(8.0)(21.0)
Foreign exchange losses (gains)0.7 6.4 (15.8)
Business development transaction costs— 24.4 — 
Write-off of previously suspended exploration wells— 13.2 4.5 
Ecuador arbitration settlement— — (26.0)
Brunei working interest income— — (16.0)
Adjusted EBITDA attributable to Murphy (Non-GAAP)$907.3 1,514.3 919.8 
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels)
60,189 63,128 44,598 
Adjusted EBITDA per barrel of oil equivalents sold$15.07 23.99 20.62 
1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest. Impairment of assets and retirement obligation gains used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest.
Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2020, are presented by segment.  More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.
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A summary of Net (loss) income is presented in the following table.
(Millions of dollars)
202020192018
Exploration and production – continuing operations
United States
$(1,014.3)518.4 242.9 
Canada
(35.0)(4.3)51.1 
Other International
(85.6)(53.5)(16.6)
Total exploration and production – continuing operations
(1,134.9)460.6 277.4 
Corporate and other
(120.3)(271.8)(108.3)
Income (loss) from continuing operations
(1,255.2)188.8 169.1 
Loss (income) from discontinued operations(7.2)1,064.5 250.3 
Net (loss) income including noncontrolling interest(1,262.4)1,253.3 419.4 
Net (loss) income attributable to noncontrolling interest(113.7)103.6 8.4 
Net (loss) income attributable to Murphy$(1,148.7)1,149.7 411.0 
A summary of oil and natural gas revenues is presented in the following table.
(Millions of dollars)
202020192018
United States – Oil and natural gas liquids
$1,335.8 2,285.8 1,277.7 
 – Natural gas
69.4 73.9 53.6 
Canada – Oil and natural gas liquids174.0 287.4 302.8 
 – Natural gas
170.6 158.4 166.3 
Other
1.8 11.6 6.1 
Total oil and natural gas revenues
$1,751.6 2,817.1 1,806.5 
Exploration and Production
Please refer to Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities in the Supplemental Oil and Natural Gas Information section for supporting tables.
2020 vs 2019
All amounts include amounts attributable to a noncontrolling interest in MP GOM (a subsidiary of Murphy Expro USA, operating and developing properties in the Gulf of Mexico) and exclude discontinued operations, unless otherwise noted.
Exploration and production (E&P) continuing operations recorded a loss of $1,134.9 million in 2020 compared to earnings of $460.6 million in 2019. The results for 2020 were unfavorably impacted by impairment charges and lower oil and natural gas liquid prices and volumes, partially offset by lower depreciation and accretion expenses, general and administrative (G&A) expenses, exploration expenses and taxes. See below for further details. Based on an evaluation of expected future cash flows from properties as of December 31, 2020, the Company did not have any other significant properties with carrying values that were impaired at that date. If quoted prices decline in future periods, the lower level of projected cash flows for properties could lead to future impairment charges being recorded. The Company cannot predict the amount or timing of impairment expenses that may be recorded in the future.
As a result of the COVID-19 pandemic and certain major global suppliers announcing crude oil supply increases in the first quarter of 2020, commodity prices were generally lower in 2020 vs 2019. Crude oil price realizations averaged $38.02 per barrel in the current year compared to $60.27 per barrel in 2019, a price decrease of 37% year over year.  U.S. natural gas realized price per thousand cubic feet (MCF) averaged $2.02 in the current year compared to $2.45 per MCF in 2019, a price decrease of 18% year over year. Canada natural gas realized price per MCF averaged U.S. $1.79 in the current year compared to U.S. $1.60 per MCF in 2019, a price increase of 12% year over year.  Oil and natural gas production costs, including associated production taxes, on a per-unit basis, were $9.81 in 2020 excluding TGP (2019: $9.66). The increase in production costs in 2020 is primarily attributable to costs associated with well workovers at Cascade and Dalmatian in the U.S. Gulf of Mexico (discussed below).
United States E&P operations reported a loss of $1,014.3 million in 2020 compared to earnings of $518.4 million in 2019.  Results were $1,532.7 million unfavorable in 2020 compared to the 2019 period primarily due to higher impairment charges ($1,152.5 million), lower revenues ($955.2 million) and higher lease operating expenses ($15.4 million), partially offset by lower income tax expense ($359.8 million), depreciation, depletion and amortization (DD&A) ($129.3 million), G&A
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Exploration and Production

($49.7 million), other operating expenses ($27.2 million) and transportation, gathering, and processing ($13.1 million). The impairment charge is primarily the result of lower future prices at the time of calculation, as a result of decreased oil demand.
Lower revenues were primarily due to lower commodity prices year over year and lower volumes in the U.S. Gulf of Mexico (as a result of shut-ins related to hurricanes and storms and lower capital expenditures). Higher lease operating expenses were due primarily to Gulf of Mexico well workovers at Cascade ($51.3 million) and Dalmatian ($20.5 million). Lower income tax expense is a result of pre-tax losses driven by the impairment charge and lower commodity prices. Lower other operating expense is primarily due to a favorable mark to market revaluation on contingent consideration (as a result of lower commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($13.8 million). Lower G&A is due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).
Canadian E&P operations reported a loss of $35.0 million in 2020 compared to income of $4.3 million in 2019.  Results were unfavorable $30.7 million compared to 2019 primarily due to lower revenue ($101.2 million) partially offset by lower DD&A ($29.8 million), lease operating expense ($20.8 million), income tax charges ($18.5 million) and G&A ($12.9 million). Lower revenues were due to lower oil and condensate prices versus the prior year and a shut-in at Terra Nova for Asset Integrity work (starting in December 2019 and expected to continue until 2022). Lower DD&A and lease operating expenses were a result of lower sales. Lower income tax expense is a result of pre-tax losses. Lower G&A is due to cost reductions and lower headcount as a result of restructuring.
Other international E&P operations reported a loss from continuing operations of $85.6 million in 2020 compared to a loss of $53.5 million in the prior year.  The 2020 results include an impairment charge of $39.7 million and lower revenues of $9.8 million in Brunei.
2019 vs 2018
E&P continuing operations recorded a profit of $460.6 million in 2019 compared to a profit of $277.4 million in 2018. The results for 2019 were favorably impacted by higher oil and natural gas volumes, lower exploration expenses, and no impairment charge, partially offset by higher lease operating expenses and transportation, gathering and processing expenses, higher G&A expenses, higher DD&A and higher taxes.
Crude oil price realizations averaged $60.27 per barrel 2019 compared to $65.87 per barrel in 2018, a price decrease of 9% year over year.  U.S. natural gas realized price per thousand cubic feet (MCF) averaged $2.45 in 2019 compared to $3.18 per MCF in 2018, a price decrease of 23% year over year. Canada natural gas realized price per MCF averaged U.S.$1.60 in 2019 compared to U.S. $1.71 per MCF in 2018, a price decrease of 6% year over year.  Oil and natural gas production costs, including associated production taxes, on a per-unit basis, were $9.66 in 2019 (2018: $9.02), which together with higher oil and natural gas volumes sold, resulted in $247.2 million higher costs in 2019.
United States E&P operations reported earnings of $518.4 million in 2019 compared to earnings of $242.9 million in 2018.  Results were $275.5 million favorable in the 2019 period compared to the 2018 period due to higher revenues ($1,034.3 million), partially offset by higher DD&A ($359.2 million), lease operating expenses ($231.0 million), transportation, gathering and processing ($97.7 million) income tax expense ($47.5 million), other operating expenses ($29.2 million) and G&A ($25.3 million). Higher revenues were primarily due to higher volumes from the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019. Higher lease operating, transportation, gathering and processing expenses and DD&A were primarily due to higher volumes. Higher income taxes were due to higher profits. Higher other operating expense was due to higher business development, acquisition transaction costs and mark to market valuation on contingent consideration. Higher G&A was due to higher long-term incentive charges.
Canadian E&P operations reported a loss of $4.3 million in 2019 compared to earnings of $51.1 million in 2018.  Results were unfavorable $55.4 million primarily due to lower revenues ($23.5 million), higher lease operating expense ($19.8 million), lower other income ($13.0 million) primarily related to more Seal insurance proceed received in 2018; and partially offset by lower income tax charges ($17.4 million). Lower revenues were due to lower oil and condensate prices than 2018 and a shut-in at Hibernia in the third quarter of 2019, partially offset by higher volumes at Kaybob Duvernay and Tupper Montney. Higher lease operating expenses were due to higher costs at Tupper Montney as a result of transferring a gain on a previous natural gas processing plant sale and lease-back transaction to equity as a result of the implementation of ASC 842 (see Note B – New Accounting Principles and Recent Accounting Pronouncements). In 2018, this gain was being credited to operating expenses equally over the life of the lease.
Other international E&P operations reported a loss from continuing operations of $53.5 million in 2019 compared to a net loss of $16.6 million in 2018.  The 2019 result included the write-off of previously suspended exploration costs of $13.2 million attributable to the CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam and lower revenues from Brunei ($10.6 million), and lower tax benefits ($12.9 million).
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Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.
(Dollars per equivalent barrel)
202020192018
Continuing operations
United States – Eagle Ford Shale   
Lease operating expense$9.08 8.70 8.84 
Severance and ad valorem taxes2.06 2.82 3.20 
Depreciation, depletion and amortization (DD&A) expense26.22 24.19 24.54 
United States – Gulf of Mexico
Lease operating expense 1
11.95 10.89 11.39 
DD&A expense13.48 16.43 16.50 
Canada – Onshore
Lease operating expense4.63 5.49 4.52 
Severance and ad valorem taxes0.07 0.07 0.06 
DD&A expense9.93 10.94 10.61 
Canada – Offshore
Lease operating expense 2
17.86 14.95 15.21 
DD&A expense12.01 13.07 13.68 
Total oil and natural gas continuing operations
Lease operating expense 3
9.34 8.95 7.87 
Severance and ad valorem taxes0.44 0.71 1.16 
DD&A expense15.36 16.98 17.25 
Total oil and natural gas continuing operations – excluding noncontrolling interest
Lease operating expense 9.10 8.81 7.87 
Severance and ad valorem taxes0.47 0.76 1.17 
DD&A expense15.49 17.05 17.28 
Discontinued Operations
Malaysia
Lease operating expense— 16.49 11.39 
DD&A expense— 4.60 11.20 
1 For the year ended December 31, 2020, lease operating expense (LOE) per barrel of oil equivalents (BOE) sold for the U.S. Gulf of Mexico excluding cost associated with well workovers was $9.52. Workovers for the year ended December 31, 2020 included Dalmatian and Cascade.
2 For the year ended December 31, 2020, Canada Offshore LOE per BOE excluding the costs associated with the Terra Nova life extension project was $5.24.
3 For the year ended December 31, 2020, total LOE per BOE excluding cost associated with Gulf of Mexico well workovers was $7.91.


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Corporate
2020 vs 2019
On May 6, 2020, the Company announced that it was closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net loss in 2020. These costs include severance, relocation, IT costs, pension curtailment and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado is classified as held for sale.
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a loss of $120.3 million in 2020 compared to a loss of $271.8 million in 2019. The $151.5 million favorable variance is primarily due to higher realized gains on forward swap commodity contracts ($239.5 million), lower interest charges ($50.2 million), lower G&A ($14.5 million), and partially offset by higher tax charges ($55.3 million), restructuring charges ($48.8 million) related to the closure of the El Dorado and Calgary offices, and impairment charges ($14.1 million). Higher realized gains on forward swap commodity contracts are due to lower market pricing whereby the contract provides the Company with a fixed price. Interest charges are lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020. As of December 31, 2020, the average forward NYMEX WTI prices for 2021 and 2022 were $48.34 and $46.76, respectively (versus fixed hedge prices of $42.77 and $44.88; see Outlook section).
2019 vs 2018
Corporate activities, as defined above, reported a net loss of $271.8 million in 2019 compared to a loss of $108.3 million in 2018. The $163.5 million unfavorable variance is due to a 2018 income tax credit ($120.0 million, related to an IRS interpretation of the Tax Act), higher interest charges ($38.6 million) primarily due to early retirement of debt, foreign exchange losses ($6.6 million; versus an $16.1 million gain in 2018), Ecuador arbitration income in 2018 ($26.0 million); partially off-set by lower losses on forward crude contracts ($41.1 million) and lower income taxes (excluding the $120 million tax act credit; $22.1 million).
Discontinued Operations
The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. 
2020 vs 2019
In 2020, discontinued operations reported a loss of $7.2 million, primarily related to charges in Malaysia following the sale of this business in 2019 (see below).
2019 vs 2018
Malaysia E&P operations reported earnings of $1,086.6 million in 2019 compared to $251.7 million in the 2018 period. Results for 2019 were favorable by $834.9 million primarily as a result of the gain on sale of Malaysia to PTT Exploration and Production Public Company Limited (PTTEP) (see Note G – Property, Plant, and Equipment). The sale closed on July 10, 2019. The Company recognized a net gain of $985.4 million on the transaction. Excluding the gain, Malaysia income was $168.2 million lower than the 2018 period principally due to lower revenues ($486.4 million), partially offset by lower operating expenses ($74.9 million), lower depreciation ($164.9 million) and lower income taxes ($73.1 million). Lower revenues are principally due to lower volumes sold as a result of a partial year of operations and declining daily production. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale and partial year of operations.









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Production Volumes and Prices
2020 vs 2019
Total hydrocarbon production from all E&P continuing operations averaged 174,636 barrels of oil equivalent per day in 2020, which represented a 6% decrease from the 185,649 barrels per day produced in 2019. Production in the Gulf of Mexico was significantly impacted by a record breaking hurricane year which resulted in shut-ins and loss of approximately 6.4 MBOED of production in 2020. Lower volumes in the Eagle Ford Shale volumes were due to lower capital expenditures.
Average crude oil and condensate production from continuing operations was 103,966 barrels per day in 2020 compared to 114,742 barrels per day in 2019. The decrease of 10,776 barrels per day was principally due to lower Eagle Ford Shale production (8,158 barrels per day) and lower volumes in the Gulf of Mexico (2,143 barrels per day) as stated above. On a worldwide basis, the Company’s crude oil and condensate prices averaged $38.02 per barrel in 2020 compared to $60.27 per barrel in the 2019 period, a decrease of 37% year over year, resulting from the global downturn triggered by the COVID-19 pandemic.
Total production of natural gas liquids (NGL) from continuing operations was 11,541 barrels per day in 2020 compared to 11,888 barrels per day in the 2019 period.  The average sales price for U.S. NGL was $11.29 per barrel in 2020 compared to $14.85 per barrel in 2019.  The average sales price for NGL in Canada was $18.54 per barrel in 2020 compared to $26.04 per barrel in 2019. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 355 million cubic feet per day (MMCFD) in 2020 compared to 354 MMCFD in 2019.  The increase of 1 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (14 MMCFD) due to a full year contribution from the assets associated with the LLOG transaction.
Natural gas prices for the total Company averaged $1.85 per thousand cubic feet (MCF) in 2020, versus $1.80 per MCF average in the same period of 2019.  Average natural gas prices in the US and Canada in 2020 were $2.02 and $1.79 per MCF, respectively.

2019 vs 2018
Total hydrocarbon production from continuing operations averaged 185,649 barrels of oil equivalent per day in 2019, which represented a 49% increase from the 124,337 barrels per day produced in 2018.  The increase was principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.
Average crude oil and condensate production from continuing operations was 114,742 barrels per day in 2019 compared to 63,438 barrels per day in 2018. The increase of 51,304 barrels per day was principally due to higher volumes in the Gulf of Mexico (48,121 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $60.27 per barrel in 2019 compared to $65.87 per barrel in 2018, a decrease of 9% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 11,888 barrels per day in 2019 compared to 8,798 per day in 2018. The average sales price for U.S. NGL was $14.85 per barrel in 2019 compared to $26.12 per barrel in 2018. The average sales price of NGL in Canada was $26.04 per barrel in 2019 compared to $37.47 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob Duvernay and Placid Montney assets.
Natural gas sales volumes from continuing operations averaged 354 million cubic feet per day (MMCFD) in 2019 compared to 313 MMCFD in 2018.  The increase of 42 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (38 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.
Natural gas prices for the total Company averaged $1.80 per thousand cubic feet (MCF) in 2019, versus $1.93 per MCF average in 2018.  Average prices in the U.S. and Canada in 2019 were $2.45 and $1.60 respectively.
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The following table contains hydrocarbons produced during the three years ended December 31, 2020.
Barrels per day unless otherwise noted
202020192018
Continuing operations
   
Net crude oil and condensate
United States
Onshore
26,420 34,578 31,787 
Gulf of Mexico 1
64,680 66,823 18,702 
Canada
Onshore
7,888 6,329 5,690 
Offshore
4,893 6,543 6,701 
Other
85 469 558 
Total net crude oil and condensate - continuing operations
103,966 114,742 63,438 
Net natural gas liquids
United States
Onshore
5,248 5,731 6,578 
Gulf of Mexico 1
4,978 4,894 1,147 
Canada
Onshore
1,315 1,263 1,073 
Total net natural gas liquids - continuing operations
11,541 11,888 8,798 
Net natural gas – thousands of cubic feet per day
United States
Onshore
27,985 30,692 31,832 
Gulf of Mexico 1
66,105 52,068 14,356 
Canada
Onshore
260,683 271,355 266,416 
Total net natural gas - continuing operations
354,773 354,115 312,604 
Total net hydrocarbons - continuing operations including NCI 2,3
174,636 185,649 124,337 
Noncontrolling interest
Net crude oil and condensate – barrels per day
(9,962)(11,226)(1,134)
Net natural gas liquids – barrels per day
(416)(507)(24)
Net natural gas – thousands of cubic feet per day 2
(3,843)(3,965)(430)
Total noncontrolling interest
(11,019)(12,394)(1,230)
Total net hydrocarbons - continuing operations excluding NCI 2,3
163,617 173,255 123,107 
Discontinued operations
Net crude oil and condensate – barrels per day
— 12,215 28,676 
Net natural gas liquids – barrels per day
— 325 792 
Net natural gas – thousands of cubic feet per day 2
— 50,758 110,223 
Total discontinued operations
— 21,000 47,839 
Total net hydrocarbons produced excluding NCI 2,3
163,617 194,255 170,946 
Estimated net hydrocarbon reserves - million equivalent barrels 3,4
714.9 825.0 844.0 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
4 December 31, 2020, 2019 and 2018, include 17.4 MMBOE, 24.6 MMBOE and 28.4 MMBOE, respectively, relating to noncontrolling interest.













36
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The following table contains hydrocarbons sold during the three years ended December 31, 2020.
Barrels per day unless otherwise noted
202020192018
Continuing operations
   
Net crude oil and condensate
United States
Onshore
26,420 34,578 31,787 
Gulf of Mexico 1
65,621 66,272 17,729 
Canada
Onshore
7,888 6,329 5,690 
Offshore
4,958 6,722 6,884 
Other
78 427 233 
Total net crude oil and condensate - continuing operations
104,965 114,328 62,323 
Net natural gas liquids
United States
Onshore
5,248 5,731 6,578 
Gulf of Mexico 1
4,978 4,894 1,147 
Canada
Onshore
1,315 1,263 1,073 
Total net natural gas liquids - continuing operations
11,541 11,888 8,798 
Net natural gas – thousands of cubic feet per day
United States
Onshore
27,985 30,692 31,832 
Gulf of Mexico 1
66,105 52,068 14,356 
Canada
Onshore
260,683 271,355 266,416 
Total net natural gas - continuing operations
354,773 354,115 312,604 
Total net hydrocarbons - continuing operations including NCI 2,3
175,635 185,235 123,222 
Noncontrolling interest
Net crude oil and condensate – barrels per day
(10,127)(11,115)(940)
Net natural gas liquids – barrels per day
(416)(507)(24)
Net natural gas – thousands of cubic feet per day 2
(3,843)(3,965)(430)
Total noncontrolling interest
(11,184)(12,283)(1,036)
Total net hydrocarbons - continuing operations excluding NCI 2,3
164,451 172,952 122,186 
Discontinued operations
Net crude oil and condensate – barrels per day
— 12,100 29,426 
Net natural gas liquids – barrels per day
— 296 786 
Net natural gas – thousands of cubic feet per day 2
— 50,758 110,223 
Total discontinued operations
— 20,856 48,583 
Total net hydrocarbons sold excluding NCI 2,3
164,451 193,808 170,769 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
















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The following table contains the weighted average sales prices excluding transportation cost deduction for the three years ended December 31, 2020. Comparative periods are conformed to current presentation.
202020192018
Weighted average Exploration and Production sales prices   
Continuing operations
Crude oil and condensate – dollars per barrel
   
United States
Onshore$36.54 59.45 67.80 
Gulf of Mexico 1
39.15 61.09 64.52 
Canada 2
Onshore32.42 50.29 53.85 
Offshore39.40 64.91 70.16 
Other
63.51 74.70 71.48 
Natural gas liquids – dollars per barrel
United States
Onshore11.67 14.60 25.68 
Gulf of Mexico 1
10.84 15.10 28.27 
Canada 2
Onshore18.54 26.04 37.47 
Natural gas – dollars per thousand cubic feet
United States
Onshore1.95 2.47 3.11 
Gulf of Mexico 1
2.04 2.43 3.35 
Canada 2
Onshore1.79 1.60 1.71 
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia 3
Sarawak— 70.39 62.38 
Block K— 65.75 65.44 
Natural gas liquids – dollars per barrel
Malaysia 3
Sarawak— 48.23 69.69 
Natural gas – dollars per thousand cubic feet
Malaysia 3
Sarawak— 3.60 3.78 
Block K— 0.24 0.24 
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
3 Prices are net of payments under the terms of the respective production sharing contracts.
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Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $802.7 million in 2020 compared to $1,489.1 million in 2019.  The decreased cash from operating activities is primarily attributable to lower revenue from sales to customers ($1,065.4 million), partially offset by higher cash payments received on forward swap commodity contracts ($239.5 million), lower general and administrative expenses ($92.5 million) and lower lease operating expenses ($5.1 million). Lower revenues were primarily due to lower commodity prices resulting from lower demand triggered by the COVID-19 pandemic and lower volumes (due to reduced capital expenditures). See above for further explanation of underlying business reasons.
Cash flow provided by continuing operations was $739.7 million higher in 2019 than in 2018 due to higher Sales volume and higher realized gain on forward crude contracts partially off-set by higher lease operating, transportation, gathering and processing expenses. Higher revenues, lease operating, transportation, gathering and processing expenses and higher depreciation expenses are principally a result of the LLOG acquisition and a full year of the 2018 MP GOM transaction, which was completed in the fourth quarter 2018.
The total reductions of operating cash flows for interest paid during the three years ended December 31, 2020, 2019, and 2018 were $191.6 million, $179.7 million, and $158.1 million, respectively. Higher cash interest paid in 2020 was due to the new 2027 notes paying interest at 5.875% and revolver borrowing during the year. Higher cash interest paid in 2019 was due to maintaining a higher average outstanding revolver balance 2019 (timing of LLOG acquisition and Malaysia disposition) and also the cost of the $500 million term loan outstanding from May to July 2019.
Cash Used for Investing Activities
Cash used for property additions and dry holes, which includes amounts expensed, were $859.0 million and $2,536.2 million in 2020 and 2019, respectively.  In 2020, this includes $113.0 million used to fund the development of the King’s Quay FPS, which is expected to be refunded on the closing of a transaction to sell this asset to a third party. Lower property additions in 2020 are a result of a significant (approximately 50%) reduction to the 2020 capital spending budget in response to the reduced commodity price environment.
In 2019 and 2018, property additions included the LLOG and MPGOM acquisitions, respectively.
The accrual basis of capital expenditures, which includes $1,261.1 million for proved property acquisitions (principally the LLOG acquisition) in 2019 and the $794.6 million MP GOM acquisition in 2018, were as follows:
Year Ended December 31,
(Millions of dollars)202020192018
Capital Expenditures   
Exploration and production$813.3 2,683.2 1,818.8 
Corporate13.3 15.0 22.7 
Total capital expenditures$826.6 2,698.2 1,841.5 
Total capital expenditures excluding proved property acquisitions$826.6 1,437.1 1,046.9 
Total capital expenditures excluding proved property acquisitions and NCI$804.9 1,402.3 1,043.9 
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Year Ended December 31,
(Millions of dollars)202020192018
Property additions and dry hole costs per cash flow statements$759.8 1,244.1 1,011.3 
Property additions King's Quay per cash flow statements113.0 100.2 — 
Acquisition of oil properties per the cash flow statements— 1,212.3 794.6 
Geophysical and other exploration expenses32.3 48.5 41.1 
Capital expenditure accrual changes and other(78.5)93.1 (5.5)
Total capital expenditures$826.6 2,698.2 1,841.5 
Capital expenditures in the exploration and production business in 2020 compared to 2019 have decreased as a result of the 2019 LLOG acquisition and in response to the current commodity price environment, resulting in lower capital expenditures in
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Table of Contents
Financial Condition (Contd.)
the Eagle Ford Shale. The King’s Quay FPS development project is expected to be refunded on the closing of a transaction to sell this asset to a third party. 
Cash Used by and Provided by Financing Activities
Net cash provided by financing activities was $39.7 million in 2020 compared to net cash used by financing activities of $1,130.0 million during 2019. In 2020, the cash provided by financing activities was principally from borrowings on the Company’s unsecured revolving credit facility ($200.0 million), partially offset by dividends paid ($96.0 million) and distributions to noncontrolling interest ($43.7 million).
The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital.  The Company generally uses its internally generated funds to finance its capital and operating expenditures, but it also maintains lines of credit with banks and will borrow as necessary to meet spending requirements. At December 31, 2020, the Company has a $1.6 billion senior unsecured guaranteed credit facility (RCF) with a major banking consortium, which expires in November 2023. As of December 31, 2020 and in the event it is required to fund investing activities from borrowings, the Company has approximately $1.4 billion available on its committed revolving credit facility.
In 2019, the cash required by financing activities of $1,130.0 million was principally from borrowings on our revolver and short-term loan ($1,725.0 million) to fund the LLOG acquisition. These borrowings, along with the opening revolver balance ($325.0 million) of $2,050.0 million were repaid in July 2019 following the completion of the Malaysia divestment. The Company issued $550 million notes due December 2027 that bear a rate of 5.875%, for net proceeds of $542.4 million; these proceeds were used to redeem a portion of the Company’s $500 million 4.00% notes due June 2022 and a portion of the Company’s $600 million 4.45% notes due December 2022 ($521.3 million in the aggregate). The Company paid an early retirement premium of $26.6 million in relation to the retirement of the debt. Finally, in 2019, the Company also used cash to buy back issued ordinary shares ($499.9 million), pay dividends ($163.7 million) and make distributions to noncontrolling interest ($128.2 million).
In 2018, net cash provided by financing activities of $143.6 million consisted of $325.0 million of borrowings on the Company’s revolving credit facility to partially fund the MP GOM transaction, which was fully repaid following the completion of the Malaysia divestment in 2019, offset by dividends paid ($173.0 million).
Working Capital
At the end of 2020, working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) amounted to a net working capital liability of $29.4 million (2019: net working capital liability of $79.0 million).  The total working capital liability reduction of $49.6 million in 2020 is primarily attributable lower accounts receivable ($164.7 million) and lower inventory ($10.0 million) offset by lower accounts payable ($195.0 million) and lower other accrued liabilities ($46.9 million). Lower accounts receivable is due to both lower sales volumes and lower commodity sales prices. Lower accounts payable is due to overall lower business activity, principally lower capital expenditures in the fourth quarter 2020 compared to 2019 resulting in both lower trade payables and capital expenditure accruals, and lower volumes resulting in lower royalties payable. Lower other accrued liabilities is principally due to lower liabilities associated with compensation awards and benefits.
Cash and cash equivalents as of December 31, 2020 totaled $310.6 million (2019: $306.8 million). Borrowings of $200.0 million from the revolving credit facility were outstanding at the end of the year (2019: no borrowings).
Cash and invested cash are maintained in several operating locations outside the United States.  At December 31, 2020, Cash and cash equivalents held outside the U.S. included U.S dollar equivalents of approximately $119.4 million (2019: $116.5 million), the majority of which was held in Canada.  In addition, approximately $10.2 million of cash were held in Brunei, respectively, and has been classified as part of Assets held for sale in the Consolidated Balance Sheets at year-end 2020.  In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.  See Note J – Income Taxes for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.
Capital Employed
At December 31, 2020, long-term debt of $2,988.1 million had increased by $184.7 million compared to December 31, 2019, as a result of net borrowing of $200.0 million on the revolving credit facility. The fixed-rate notes had a weighted average maturity of 6.8 years and a weighted average coupon of 5.9%.
A summary of capital employed at December 31, 2020 and 2019 follows.
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Financial Condition (Contd.)
December 31, 2020December 31, 2019
(Millions of dollars)Amount%Amount%
Capital employed    
Long-term debt$2,988.1 41.5 %$2,803.4 33.9 %
Murphy shareholders' equity4,214.3 58.5 %5,467.5 66.1 %
Total capital employed$7,202.4 100.0 %$8,270.8 100.0 %
Murphy shareholders’ equity was $4.21 billion at the end of 2020 (2019: $5.47 billion). Shareholders’ equity decreased in 2020 primarily due to the net loss ($1.15 billion), which was driven by impairment charges ($1.21 billion) as a result of lower future prices at the time of calculation, as a result of decreased oil demand. A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 64 of this Form 10-K report.
Other Balance Sheet Activity - Long Term Assets and Liabilities
Other significant changes in Murphy’s balance sheet at the end of 2020, compared to 2019 are discussed below.
Property, plant and equipment, net of depreciation decreased $1,700.7 million principally due to impairment charges ($1,206.3 million) primarily the result of lower forecast future prices, as a result of decreased oil demand triggered by the COVID-19 pandemic and an annual charge of depreciation, depletion and amortization. Capital expenditures are discussed above in the ‘Cash Used for Investing Activities’ section.
Murphy had commitments for capital expenditures of approximately $747.0 million at December 31, 2020 (2019: $574.5 million).  This amount includes $529.0 million for approved expenditure for capital projects relating to non-operated interests in deepwater U.S. Gulf of Mexico, principally at St Malo ($392.5 million) and Lucius ($113.2 million).
Operating lease assets and liabilities increased $329.4 million principally due to the addition of a 5-year lease for the Cascade/Chinook FPSO in the U.S. Gulf of Mexico ($268.8 million) and a 20-year lease related to a gas plant expansion in Canada ($168.4 million).
Deferred income tax assets increased $266.0 million as a result of the increase in the estimated U.S. net operating loss of $2.8 billion at year-end 2020, up from $2.4 billion at year-end 2019.
Long-term asset retirement obligations decreased $9.5 million to $816.3 million, principally due to lower cost estimates.
Deferred credits and other liabilities increased $67.2 million primarily as a result of the pension remeasurement which was triggered by the restructuring. The Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction of force.
At December 31, 2020, the Company had $200.0 million of outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.  Borrowings under the RCF bear interest at rates, based, at the Company’s option, on the “Alternate Base Rate” of interest in effect plus the “ABR Spread” or the “Adjusted LIBOR Rate,” which is a periodic fixed rate based on LIBOR with a term equivalent to the interest period for such borrowing, plus the “Eurodollar Spread.” The “Alternate Base Rate” of interest is the highest of (i) the Wall Street Journal prime rate, (ii) the New York Federal Reserve Bank Rate plus 0.50%, and (iii) one-month LIBOR plus 1.00%. The “Eurodollar Spread” ranges from 1.075% to 2.10% per annum based upon the Corporation’s senior unsecured long-term debt securities credit ratings (the “Credit Ratings”). A facility fee accrues and is payable quarterly in arrears at a rate ranging from 0.175% to 0.40% per annum (based upon the Company’s Credit Ratings) on the aggregate commitments under the 2018 facility.  At December 31, 2020, the interest rate in effect on borrowings under the facility was 1.84%.  At December 31, 2020, the Company was in compliance with all covenants related to the RCF.
Environmental, Health and Safety Matters
Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons.  To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels.  The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, and through emergency and oil spill response planning to address any credible risks. These plans are presented to, reviewed and approved by a health, safety, environmental and corporate responsibility committee consisting of certain members of Murphy’s Board of Directors.

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Environmental Matters (Cont’d.)
The oil and natural gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations.  Murphy allocates a portion of both its capital expenditures and its general and administrative budget toward compliance with existing and anticipated environmental, health and safety laws and regulations.  These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities as well as operating costs for ongoing compliance.
The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.
Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the Business section beginning page 9.
Climate Change
The world’s population and standard of living is growing steadily along with the demand for energy. Murphy recognizes that this generates increasing amounts of greenhouse gases (GHGs), which raise important climate change concerns. Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the Task Force for Climate-related Financial Disclosures (TCFD) core elements. The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of climate-related financial information. Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2020 Sustainability Report issued on October 9, 2020, which is not incorporated by reference hereto.
During 2020, the Company made significant strides in our sustainability efforts, including:
•Establishing a further goal of reducing our GHG emissions intensity 15 percent to 20 percent by 2030 from our 2019 levels, excluding divested assets from the 2019 baseline, for an aggregate of 35 percent to 40 percent reduction from our reported 2019 levels;
•Expanding our GHG, air quality, climate risk management and biodiversity management public disclosures; and
•Expanding the purview of our health, safety, environmental and corporate responsibility committee consisting of certain members of Murphy’s Board of Directors to include environmental, social and governance (ESG) issues, and creating a director of sustainability role.
Other Matters
Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas and allied industries than by changes in general inflation.  Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the future.  Prices for oil field goods and services are usually affected by the worldwide prices for crude oil. 
In 2020, some downward service cost relief was observed. In 2019 the cost of goods and services in the oil and natural gas industry were stable.
Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas is generally restricted to specific geographic areas.
As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.




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Accounting changes and recent accounting pronouncements – see Note B – New Accounting Principles and Recent Accounting Pronouncements
SEC Rules Adopted
SEC Disclosures Modernization of Regulation S-K Items 101, 103, and 105. The new rules, which are part of the U.S. Securities and Exchange Commission’s (SEC) broader project to modernize Regulation S-K, became effective November 9, 2020. As a result, 2020 Form 10-Ks and other filings subject to Regulation S-K filed on or after this date need to include the new disclosures. The new disclosures include principles-based disclosure of information material to an understanding of the general development of the business, and eliminating the previously prescribed five-year timeframe, a description of the registrant’s human capital resources to the extent such disclosures would be material to an understanding of the registrant’s business, and disclosure of any alternative threshold chosen for disclosure of environmental proceedings.
SEC Disclosures Update and Simplification. In August 2018, the U.S. Securities and Exchange Commission (SEC) adopted the final rule under SEC Release No. 33-10532 Disclosure Update and Simplification, to eliminate or modify certain disclosure rules that are redundant, outdated, or duplicative of U.S. GAAP or other regulatory requirements. Among other changes, the amendments eliminated the annual requirement to disclose the high and low trading prices of our common stock and the ratio of earnings to fixed charges. In addition, the amendments provide that disclosure requirements related to the analysis of shareholders’ equity are expanded for interim financial statements. An analysis of the changes in each caption of shareholders’ equity presented in the balance sheet must be provided in a note or separate statement, as well as the amount of dividends per share for each class of shares. This rule was effective on November 5, 2018; and the expanded interim disclosure requirements for changes in shareholders’ equity was effective for the Company for our quarterly reporting beginning March 31, 2019.
SEC Rules Not Yet Adopted
SEC Disclosures Management’s Discussion and Analysis (MD&A), Selected Financial Data, and Supplementary Financial Information. The new rules, which are part of the SEC’s broader project to modernize Regulation S-K, were published January 11, 2021 and became effective February 10, 2021. The rules can be applied 30 days after publication in the Federal Register, and compliance is mandatory 210 days after publication. Before the mandatory compliance date, registrants can choose which amended items to apply. The amendments are intended to modernize, simplify, and enhance certain financial disclosure requirements in Regulation S-K. Specifically, they eliminate the requirement for Selected Financial Data, streamline the requirement to disclose Supplementary Financial Information, and amend MD&A. These amendments are intended to eliminate duplicative disclosures and modernize and enhance MD&A disclosures for the benefit of investors, while simplifying compliance efforts for registrants.
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Other Matters (Cont’d.)
Significant accounting policies – In preparing the Company’s consolidated financial statements in accordance with U.S. GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  Application of certain of the Company’s accounting policies requires significant estimates.  The most significant of these accounting policies and estimates are described below.
Oil and natural gas proved reserves – Oil and natural gas proved reserves are defined by the SEC as those quantities of oil and natural gas, which, 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 before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain).  Proved developed reserves of oil and natural gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 
Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment.  SEC rules require the Company to use an unweighted average of the oil and natural gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves.  These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future.  The Company often uses significantly different oil and natural gas price and reserve assumptions when making its own internal economic property evaluations.  Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities. 
Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.  Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations.  Downward reserves revisions can also lead to significant impairment expense.  The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods. 
The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented on pages 102 to 110 of this Form 10-K report.  Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish ‘reasonable certainty’ of economic producibility.  As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered.  In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog-based studies. 
Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves.  Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.  This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. It was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques.  Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs.  Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.
See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2020 beginning on pages 5 and 102 of this Form 10-K report.
Property, Plant & Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, plant and equipment (PPE) in the Consolidated Balance Sheet to make sure that they are fairly presented.  The Company must evaluate its PPE for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. 
A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.  Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs, and future inflation levels. 
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Other Matters (Cont’d.)
Significant accounting policies (Cont’d.)
The need to test a long-lived asset for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment. 
Due to the volatility of world oil and natural gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections. 
Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable and possible reserves.  Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection.  The Company adjusts reserves and production estimates as new information becomes available. 
The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations.  Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. 
In 2020, declines in future oil and natural gas prices (principally driven by reduced commodity demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties and assets. In 2020, the Company recognized pretax noncash impairment charges of $1,206.3 million to reduce the carrying values at select properties. 
There were no impairments in 2019.
As a result of management’s assessments during 2018, the Company recognized a pretax, noncash impairment charge of $20.0 million at select Midland properties. See also Note G – Property, Plant, and Equipment for further discussion of impairment charges. 
Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.
The Company has deferred tax assets mostly relating to U.S net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant & equipment.
The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduce such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider all available positive and negative evidence. Positive evidence includes projected future taxable income and assessment of future business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences. Negative evidence includes losses in recent years.
As at December 31, 2020 the Company had a U.S. deferred tax asset associated with net operating losses of $589.1 million. In reviewing the likeliness of realizing this asset the Company considered the reversal of taxable temporary differences, carryforward periods, and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur. Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil and condensate, NGLs and natural gas, (b) estimated reserves for crude oil and condensate, NGLs and natural gas, (c) expected timing of production, (d) estimated lease operating costs, and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.
Accounting for retirement and postretirement benefit plans – Murphy and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees.  The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees.  The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries.  The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of
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Other Matters (Cont’d.)
Significant accounting policies (Cont’d.)
return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate.  Discount rates are based on the universe of high-quality corporate bonds that are available within each country.  Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans.  The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country.  Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics.  Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.
Based on bond yields at December 31, 2020, the Company has used a weighted average discount rate of 2.47% at year-end 2020 for the primary U.S. plans.  This weighted average discount rate is 0.9% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago.  Although the Company presently assumes a return on plan assets of 5.50% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions.  The Company’s retirement and postretirement plan expenses in 2021 are expected to be $12.3 million lower than 2020 primarily due to termination benefit charges recorded relating to the restructuring in 2020 and lower interest charges.  Cash contributions are anticipated to be $9.9 million higher in 2021.  
In 2020, the Company paid $30.2 million into various retirement plans and $1.8 million into postretirement plans.  In 2021, the Company is expecting to fund payments of approximately $36.6 million into various retirement plans and $5.3 million for postretirement plans.  The Company could be required to make additional and more significant funding payments to retirement plans in future years.  Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected. 

Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans, and other long-term liabilities.  Total payments due after 2020 under such contractual obligations and arrangements are shown in the table below.
(Millions of dollars)Amount of Obligations
Total20212022 - 20232024 - 2025After 2025
Debt, excluding interest$2,809.7 — 576.4 1,091.1 1,142.2 
Operating leases and other leases ¹1,357.3 150.2 279.1 215.7 712.4 
Capital expenditures, drilling rigs and other ²1,756.7 746.7 434.5 175.7 399.8 
Other long-term liabilities, including debt interest ³2,575.4 267.5 375.6 453.5 1,478.8 
Total$8,499.1 1,164.3 1,665.6 1,936.0 3,733.2 
1 Other leases refers to a finance lease in Brunei, which is classified as held for sale as of December 31, 2020 (see Note E – Assets Held for Sale and Discontinued Operations).
2 Capital expenditures, drilling rigs and other includes $529.0 million and $31.5 million in the years 2021 to 2023 for approved capital projects in non-operated interests in U.S. Gulf of Mexico and U.S. Onshore, respectively. Also includes $56.7 million (2021), $117.0 million (2022 - 2023), $90.9 million (2024 - 2025) and $254.3 million (After 2025) for pipeline transportation commitments in Canada. Also includes $4.3 million (2021), $9.8 million (2022 - 2023), $10.4 million (2024 - 2025) and $37.2 million (After 2025) for long term take or pay commitments relating to gas processing in Canada.
3 Other long-term liabilities, including debt interest includes future cash outflows for asset retirement obligations.
The Company has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that call for future payments as described in the following section.  The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.
In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts.  Total outstanding letters of credit were $210.6 million as of December 31, 2020.
Material off-balance sheet arrangements – Certain U.S. transportation contracts require minimum monthly payments through 2045, while Western Canada processing contracts call for minimum monthly payments through 2051.  Future required minimum annual payments under these arrangements are included in the contractual obligation table above. 
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Outlook
Prices for the Company’s primary products are often volatile.  The price of crude oil is primarily affected by the levels of supply and demand for energy.  Anticipated future variances between the predicted demand for crude oil and the projected available supply can lead to significant movement in the price of crude oil.  As of close on February 25, 2021, the NYMEX WTI forward curve price for the remainder of 2021 and 2022 were $61.38 and $56.51 per barrel, respectively; however we cannot predict what impact the ongoing COVID-19 pandemic and other economic factors may have on future commodity pricing. Lower prices are expected to result in lower profits and operating cash-flows. The Company is closely monitoring the impact of lower commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note H – Financing Arrangements and Debt). The Company’s response to COVID-19 is discussed in more detail in the Risk Factors – General Risks.
The Company’s capital expenditure spend for 2021 is expected to be between $675.0 million and $725.0 million. Capital and other expenditures will be routinely reviewed during 2021 and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year.  Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.  The Company will primarily fund its capital program in 2021 using operating cash flow and available cash, but will supplement funding where necessary with borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.  
The Company currently expects average daily production in 2021 to be between 164,800 and 174,800 barrels of oil equivalent per day (including noncontrolling interest of 9,800 BOEPD). If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.
The Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
CommodityTypeVolumes
(Bbl/d)		Price
(USD/Bbl)		Remaining Period
AreaStart DateEnd Date
United StatesWTI ¹Fixed price derivative swap45,000 $42.77 1/1/202112/31/2021
United StatesWTI ¹Fixed price derivative swap20,000 $44.88 1/1/202212/31/2022
1 West Texas Intermediate
Volumes
(MMcf/d)		Price
(CAD/Mcf)		Remaining Period
AreaCommodityTypeStart DateEnd Date
MontneyNatural GasFixed price forward sales at AECO160C$2.541/1/20211/31/2021
MontneyNatural GasFixed price forward sales at AECO203C$2.552/1/20215/31/2021
MontneyNatural GasFixed price forward sales at AECO212C$2.556/1/202112/31/2021
MontneyNatural GasFixed price forward sales at AECO222C$2.411/1/202212/31/2022
MontneyNatural GasFixed price forward sales at AECO192C$2.361/1/202312/31/2023
MontneyNatural GasFixed price forward sales at AECO147C$2.411/1/202412/31/2024
Forward-Looking Statements
This Form 10-K contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where
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we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see Item 1A. Risk Factors, which begins on page 14 of this Annual Report on Form 10-K.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  As described in Note M – Financial Instruments and Risk Management, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at December 31, 2020, covering certain future U.S. crude oil sales volumes in 2021 and 2022. A 10% increase in the respective benchmark price of these commodities would have increased the net payable associated with these derivative contracts by approximately $104.7 million, while a 10% decrease would have decreased the recorded payable by a similar amount, resulting in a receivable.
There were no derivative foreign exchange contracts in place at December 31, 2020.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item appears on pages 55 through 119 of this Form 10-K report.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
Item 9A. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, with the participation of the Company’s management, as of December 31, 2020, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f).  Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2020.  KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2020 and their report is included on page 59 of this Form 10-K report.
There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. OTHER INFORMATION
None
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PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Certain information regarding executive officers of the Company is included on page 25 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2021 under the captions “Election of Directors” and “Committees.”
Murphy Oil has adopted a Code of Ethical Conduct, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com.  Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at 9805 Katy Fwy, Suite G-200, Houston, TX 77024.  Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s Website.
Item 11. EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2021 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors” and in various compensation schedules.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2021 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2021 under the caption “Election of Directors.”
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2021 under the caption “Audit Committee Report.”
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PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)    1.    Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below.
Page No.
2.    Financial Statement Schedules
All other financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
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3.    Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable.
Exhibit
No.		 Incorporated by Reference to the Indicated Filing by
Murphy Oil Corporation
2.1Exhibit 2.1 to Form 8-K filed June 5, 2019
2.2Exhibit 2.2 to Form 8-K filed June 5, 2019
2.3Exhibit 2.1 to Form 10-K for the year ended December 31, 2018
2.4Exhibit 10.3 to Form 10-Q filed May 2, 2019
3.1Exhibit 3.1 to Form 10-K for the year ended December 31, 2010
3.2Exhibit 3.2 to Form 8-K filed February 5, 2016
4.1Exhibit 4.2 to Form 10-K for the year ended December 31, 2004
4.2Exhibit 4.2 to Form 10-K for the year ended December 31, 2004
4.3Exhibit 4.1 to Form 8-K filed May 18, 2012
4.4Exhibit 4.2 to Form 8-K filed May 18, 2012
4.5Exhibit 4.1 to Form 8-K filed November 30, 2012
4.6Exhibit 4.1 to Form 8-K filed August 17, 2016
4.7Exhibit 4.1 to Form 8-K filed August 18, 2017
4.8Exhibit 4.2 to Form 8-K filed November 27, 2019
4.9Exhibit 4.9 to Form 10-K filed on February 27, 2020
10.1Exhibit 10.1 to Form 8-K filed August 12, 2016
10.2Exhibit 10.1 to Form 8-K filed November 20, 2017
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10.3Exhibit 10.1 to Form 8-K filed October 11, 2018
10.4Exhibit 10.4 to Form 10-K for the year ended December 31, 2018
10.7Exhibit A to definitive proxy statement filed March 29, 2012
10.8Exhibit 10.8 to Form 10-K filed on February 27, 2020
10.9Exhibit 99.1 to Form 10-K for the year ended December 31, 2013
10.10Exhibit 99.2 to Form 10-K for the year ended December 31, 2014
10.11Exhibit 99.3 to Form 10-Q filed May 7, 2014
10.12Exhibit 99.1 to Form 10-Q filed May 7, 2014
10.13Exhibit 99.2 to Form 10-Q filed May 7, 2014
10.14Exhibit B to definitive proxy statement filed March 23, 2018 
10.15Exhibit 10.15 to Form 10-K filed on February 27, 2020
10.16Exhibit 10.14 to Form 10-K for the year ended December 31, 2018
10.17Exhibit 10.17 to Form 10-K filed on February 27, 2020
10.18Exhibit 10.15 to Form 10-K for the year ended December 31, 2018
10.19Exhibit 10.16 to Form 10-K for the year ended December 31, 2018
10.20Exhibit A to definitive proxy statement filed March 30, 2020
*10.21
*10.22
*10.23
*10.24
*10.25
10.26Exhibit A to definitive proxy statement filed March 22, 2013
10.27Exhibit 99.2 to Form 10-Q filed November 6, 2013
10.28Exhibit A to definitive proxy statement filed March 23, 2018
10.29Exhibit 10.1 to Form 8-K filed April 25, 2018
10.30Exhibit 10.24 to Form 10-K filed on February 27, 2020
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10.31Exhibit 10.20 to Form 10-K for the year ended December 31, 2018
10.32Exhibit 10.26 to Form 10-K filed on February 27, 2020
10.33Exhibit 10.6 to Form 10-K for the year ended December 31, 2015
10.34Exhibit 10.1 to Form 8-K filed September 5, 2013
10.35Exhibit 10.3 to Form 8-K filed September 5, 2013
10.36Exhibit 10.4 to Form 8-K filed September 5, 2013
*21.1 
*23.1 
*23.2
*23.3
*31.1 
*31.2 
*32.1 
*99.1 
*99.2 
*99.3 
101.INSXBRL Instance Document 
101.SCHXBRL Taxonomy Extension Schema Document 
101.CALXBRL Taxonomy Extension Calculation Linkbase Document 
101.DEFXBRL Taxonomy Extension Definition Linkbase Document 
101.LABXBRL Taxonomy Extension Labels Linkbase Document 
101.PREXBRL Taxonomy Extension Presentation Linkbase 
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MURPHY OIL CORPORATION
By/s/ ROGER W. JENKINS Date:February 26, 2021 
Roger W. Jenkins, President    
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 26, 2021 by the following persons on behalf of the registrant and in the capacities indicated.
  
/s/ CLAIBORNE P. DEMING /s/ R. MADISON MURPHY
Claiborne P. Deming, Chairman and Director R. Madison Murphy, Director
  
  
/s/ ROGER W. JENKINS /s/ WALENTIN MIROSH
Roger W. Jenkins, President and
Chief Executive Officer and Director
(Principal Executive Officer)		 Walentin Mirosh, Director
  
/s/ T. JAY COLLINS /s/ JEFFREY W. NOLAN
T. Jay Collins, Director Jeffrey W. Nolan, Director
 
/s/ STEVEN A. COSSE /s/ ROBERT N. RYAN, JR.
Steven A. Cossé, Director Robert N. Ryan, Jr., Director
  
/s/ LAWRENCE R. DICKERSON /s/ NEAL E. SCHMALE
Lawrence R. Dickerson, Director Neal E. Schmale, Director
  
/s/ ELISABETH W. KELLER /s/ LAURA A. SUGG
Elisabeth W. Keller, Director Laura A. Sugg, Director
  
/s/ JAMES V. KELLEY /s/ DAVID R. LOONEY
James V. Kelley, Director David R. Looney, Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
/s/ CHRISTOPHER D. HULSE
Christopher D. Hulse
Vice President and Controller
(Principal Accounting Officer)
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REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS
The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data.  The financial statements were prepared in conformity with U.S. generally accepted accounting principles (GAAP) appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.
An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the Company’s consolidated financial statements.  The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders. KPMG LLP’s opinion covering the Company’s consolidated financial statements can be found on page 56.
The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm.  This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter.  The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.
REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f).  The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. GAAP.  All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements.
Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.  Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2020.
KPMG LLP has performed an audit of the Company’s internal control over financial reporting and their opinion thereon can be found on page 59.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Murphy Oil Corporation:

Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2020, and the related notes and financial statement schedule II (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note B to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update No. 2016-02, Leases.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters     below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Estimated oil and gas reserves used in the depletion of producing oil and gas properties

As discussed in Note A to the consolidated financial statements, the Company calculates depletion expense related to producing oil and gas properties using the units-of-production method. Under this method, costs to acquire interests in oil and gas properties and costs for the drilling and completion efforts for exploratory wells that find proved reserves and for development wells are capitalized. Capitalized costs of producing oil and gas properties, along with equipment and facilities that support production, are amortized to expense by the units-of-production method. The Company’s internal petroleum reserve engineers estimate proved oil and gas reserves and the Company engages third-party petroleum reserve specialists to perform an independent assessment. For the year ended December 31, 2020, the Company recorded depreciation, depletion, and amortization expense of $987.2 million.
We identified the assessment of the estimated oil and gas reserves used in the depletion of producing oil and gas properties as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of
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total proved oil and gas reserves, which is an input to the depletion expense calculation. Estimating proved oil and gas reserves requires the expertise of professional petroleum reserve engineers based on their estimates of forecasted production, forecasted operating costs, future development costs, and oil and gas prices.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion calculation process, including controls related to the estimation of proved oil and gas reserves. We evaluated (1) the professional qualifications of the internal petroleum reserve engineers, third-party petroleum reserve specialists, and external engineering firm, (2) the knowledge, skills, ability of the Company’s internal petroleum reserve engineers and third-party petroleum reserve specialists, and (3) the relationship of the third-party petroleum reserve specialists and external engineering firm to the Company. We analyzed and assessed the calculation of depletion expense for compliance with industry and regulatory standards. We compared the forecasted production assumptions used by the Company to historical production rates. We compared the forecasted operating costs to historical results. We also evaluated the forecasted nature and timing of future development costs by obtaining an understanding of the development projects and comparing the development projects with the available development plans. We assessed the oil and gas prices utilized by the internal petroleum reserve engineers by comparing them to publicly available prices and recalculated the relevant market differentials. In addition, we read and considered the report of the Company’s third-party petroleum reserve specialists in connection with our evaluation of the Company’s proved oil and gas reserve estimates.

Evaluation of the realizability of deferred tax assets

As discussed in Note J to the consolidated financial statements, the Company had gross deferred tax assets of $1,018.9 million, which includes U.S. net operating losses of $589.1 million, as of December 31, 2020. A valuation allowance is provided for deferred tax assets if it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period, which is dependent upon the generation of taxable income.

We identified the evaluation of the realizability of deferred tax assets as a critical audit matter. The evaluation of the realizability of deferred tax assets, specifically those related to U.S. net operating loss carryforwards, required subjective auditor judgment to assess the application of tax laws and the projections of future taxable income over the periods in which those temporary differences become deductible. Changes in assumptions regarding future taxable income could have a significant impact on the Company’s evaluation of the realizability of the deferred tax assets.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s evaluation of the realizability of deferred tax assets, including controls related to the application of tax laws and the development of projections of future taxable income. We evaluated the assumptions used in the development of projected future taxable income by comparing such assumptions to estimated oil and gas reserve quantities developed by the Company, by comparing projected cost estimates to historical actual costs, and by comparing future commodity prices used in the determination of projected future taxable income to external sources. We also evaluated the Company’s history of realizing deferred tax assets by evaluating the expiration of net operating loss carryforwards and testing the reversal pattern of taxable temporary differences. We involved income tax professionals with specialized skills and knowledge who assisted in assessing the Company’s application of tax laws.

Impairment assessment of property, plant, and equipment related to oil and gas properties
As discussed in Note A to the consolidated financial statements, the Company reviews their oil and gas properties for triggering events that would indicate potential impairment. The Company analyzes indicators for possible triggers of impairment such as a significant reduction in sales prices for oil or natural gas, unfavorable revisions of oil or natural gas reserves, changes to contracts, environmental regulations, tax law or other regulatory changes. If a triggering event is identified in relation to one or more properties, an undiscounted cash flow analysis is required to quantitatively evaluate recoverability. When the carrying amount of an oil and gas property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Estimated future net cash flows used to estimate fair value are based on forecasted production of oil and gas reserves, commodity prices based on published forward price curves or contract prices as of the date of the estimate, operating and development costs, and a discount rate. The Company recorded impairment expense of $1,206.3 million related to property, plant, and equipment for the year ended December 31, 2020.

We identified the evaluation of the impairment assessment of property, plant, and equipment related to oil and gas properties as a critical audit matter. There is a high degree of subjectivity in the evaluation of the estimate of oil and gas reserves used to determine future cash flows in such assessment due to (1) the uncertainty associated with future commodity prices and estimated future production, (2) risk adjustment factors associated with reserve volumes, and (3)
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the judgment inherent in forecasting capital and operating costs and selecting a discount rate to apply in the Company’s assessment.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s property, plant, and equipment process for oil and gas properties, including controls over the Company’s impairment assessment process and oil and gas reserve estimation process. We evaluated (1) the professional qualifications of the Company’s internal petroleum reserve engineers, third-party petroleum reserve specialists, and external engineering firm, (2) the knowledge, skills, and ability of the Company’s internal petroleum reserve engineers and third-party petroleum reserve specialists, and (3) the relationship of the third-party petroleum reserve specialists and external engineering firm to the Company. We evaluated the Company’s cash flow analysis related to forecasted production, capital, and operating costs by comparing to historical results and future development plans. We compared future commodity price assumptions to publicly available market information. We evaluated risk adjustment factors associated with reserve volumes by comparing to guideline ranges by reserve class in published industry surveys. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the discount rate used in the valuation by comparing it against a discount rate range that was independently developed using publicly available market data for comparable entities.

/s/ KPMG LLP
We have served as the Company’s auditor since 1952.
Houston, Texas
February 26, 2021
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Murphy Oil Corporation:

Opinion on Internal Control Over Financial Reporting
We have audited Murphy Oil Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2020, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 26, 2021 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of Management - Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas
February 26, 2021
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31 (Thousands of dollars except share amounts)20202019
ASSETS
Current assets
Cash and cash equivalents$310,606 306,760 
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2020 and 2019
262,014 426,684 
InventoriesNote F66,076 76,123 
Prepaid expenses33,860 40,896 
Assets held for saleNote E327,736 123,864 
Total current assets1,000,292 974,327 
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,455,305 in 2020 and $9,333,646 in 2019
Note G8,269,038 9,969,743 
Operating lease assetsNote V927,658 598,293 
Deferred income taxesNote J395,253 129,287 
Deferred charges and other assets28,611 46,854 
Total assets$10,620,852 11,718,504 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable$407,097 602,096 
Income taxes payable18,018 19,049 
Other taxes payable22,498 18,613 
Operating lease liabilities103,758 92,286 
Other accrued liabilities150,578 197,447 
Liabilities associated with assets held for saleNote E14,372 13,298 
Total current liabilities716,321 942,789 
Long-term debt, including capital lease obligationNote H2,988,067 2,803,381 
Asset retirement obligations
Note I
816,308 825,794 
Deferred credits and other liabilities680,580 613,407 
Non-current operating lease liabilitiesNote V845,088 521,324 
Deferred income taxesNote J180,341 207,198 
Total liabilities6,226,705 5,913,893 
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
— — 
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2020 and 195,089,269 shares in 2019
195,101 195,089 
Capital in excess of par value941,692 949,445 
Retained earnings5,369,538 6,614,304 
Accumulated other comprehensive lossNote P(601,333)(574,161)
Treasury stock(1,690,661)(1,717,217)
Murphy Shareholders' Equity4,214,337 5,467,460 
Noncontrolling interest179,810 337,151 
Total equity4,394,147 5,804,611 
Total liabilities and equity$10,620,852 11,718,504 
1 See Notes to Consolidated Financial Statements, page 65.
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31 (Thousands of dollars except per share amounts)20202019 2018
Revenues and other income
 
 
 
Revenue from sales to customers$1,751,709 2,817,111 1,806,473 
(Loss) gain on crude contracts202,661 (856)(41,975)
Gain on sale of assets and other income12,971 12,798 26,903 
Total revenues and other income1,967,341 2,829,053 1,791,401 
Costs and expenses
Lease operating expenses600,076 605,180 353,832 
Severance and ad valorem taxes28,526 47,959 52,072 
Transportation, gathering and processing 172,399 176,315 75,043 
Exploration expenses, including undeveloped lease amortization86,479 95,105 101,812 
Selling and general expenses140,243 232,736 205,192 
Restructuring expenses49,994 — — 
Depreciation, depletion and amortization987,239 1,147,842 775,614 
Accretion of asset retirement obligations42,136 40,506 27,119 
Impairment of assets1,206,284 — 20,000 
Other (benefit) expense16,274 38,117 (34,870)
Total costs and expenses3,329,650 2,383,760 1,575,814 
Operating (loss) income from continuing operations(1,362,309)445,293 215,587 
Other income (loss)
Interest and other income (loss)(17,303)(22,520)7,774 
Interest expense, net(169,423)(219,275)(180,359)
Total other loss(186,726)(241,795)(172,585)
(Loss) income from continuing operations before income taxes(1,549,035)203,498 43,002 
Income tax (benefit) expense (293,741)14,683 (126,136)
(Loss) income from continuing operations(1,255,294)188,815 169,138 
(Loss) income from discontinued operations, net of income taxes(7,151)1,064,487 250,348 
Net income (loss) including noncontrolling interest(1,262,445)1,253,302 419,486 
Less: Net (loss) income attributable to noncontrolling interest(113,668)103,570 8,392 
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY$(1,148,777)1,149,732 411,094 
(LOSS) INCOME PER COMMON SHARE – BASIC
Continuing operations$(7.43)0.52 0.92 
Discontinued operations(0.05)6.49 1.46 
Net income (loss)$(7.48)7.01 2.38 
(LOSS) INCOME PER COMMON SHARE – DILUTED
Continuing operations$(7.43)0.52 0.92 
Discontinued operations(0.05)6.46 1.44 
Net income (loss)$(7.48)6.98 2.36 
Cash dividends per Common share$0.625 1.00 1.00 
Average Common shares outstanding (thousands)
Basic153,507 163,992 172,974 
Diluted153,507 164,812 174,209 
1 See Notes to Consolidated Financial Statements, page 65.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Years Ended December 31 (Thousands of dollars)202020192018
Net income (loss) including noncontrolling interest
$(1,262,445)1,253,302 419,486 
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation
29,241 66,600 (145,022)
Retirement and postretirement benefit plans
(57,617)(35,979)29,110 
Deferred loss on interest rate hedges reclassified to interest expense
1,204 5,005 2,342 
Reclassification of certain tax effects to retained earnings
— — (30,237)
Other
— — (3,737)
Other comprehensive income (loss)
(27,172)35,626 (147,544)
COMPREHENSIVE INCOME (LOSS)
$(1,289,617)1,288,928 271,942 
See Notes to Consolidated Financial Statements, page 65.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31 (Thousands of dollars)20202019 2018 ¹
Operating Activities
Net income (loss) including noncontrolling interest$(1,262,445)1,253,302 419,486 
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:
(Income) loss from discontinued operations7,151 (1,064,487)(250,348)
Depreciation, depletion and amortization987,239 1,147,842 775,614 
Previously suspended exploration costs 21,099 12,840 20,508 
Amortization of undeveloped leases26,743 27,973 40,177 
Accretion of asset retirement obligations42,136 40,506 27,119 
Impairment of assets1,206,284 — 20,000 
Noncash restructuring expense17,565 — — 
Deferred income tax charge (benefit)(278,042)28,530 (177,627)
Mark to market loss (gain) on contingent consideration(13,783)8,672 (4,810)
Mark to market loss (gain) on crude contracts69,310 33,364 (33,954)
Long-term non-cash compensation46,558 76,958 72,151 
Net (increase) decrease in noncash operating working capital(32,027)(16,887)(16,103)
Other operating activities, net(35,080)(59,508)(142,818)
Net cash provided by continuing operations activities802,708 1,489,105 749,395 
Investing Activities
Property additions and dry hole costs(759,809)(1,244,069)(1,011,292)
Property additions for King's Quay FPS(112,961)(100,202)— 
Proceeds from sales of property, plant and equipment13,750 20,382 1,175 
Acquisition of oil and natural gas properties— (1,212,315)(794,623)
Net cash required by investing activities(859,020)(2,536,204)(1,804,740)
Financing Activities
Borrowings on revolving credit facility and term loan450,000 1,725,000 325,000 
Repayment of revolving credit facility and term loan(250,000)(2,050,000)— 
Cash dividends paid(95,989)(163,669)(173,044)
Distributions to noncontrolling interest(43,673)(128,158)— 
Early retirement of debt(12,225)(521,332)— 
Withholding tax on stock-based incentive awards(7,094)(6,991)(8,076)
Debt issuance, net of cost(613)542,394 — 
Capital lease obligation payments(695)(688)(318)
Loss on early extinguishment of debt— (26,626)— 
Repurchase of common stock— (499,924)— 
Net cash (required) provided by financing activities39,711 (1,129,994)143,562 
Cash Flows from Discontinued Operations 2
Operating activities(1,202)73,783 406,857 
Investing activities4,494 2,022,034 (91,398)
Financing activities— (4,914)(9,432)
Net cash provided by discontinued operations3,292 2,090,903 306,027 
Cash from discontinued operations 18,438 2,120,397 612,543 
Effect of exchange rate changes on cash and cash equivalents2,009 3,533 28,730 
Net increase (decrease) in cash and cash equivalents3,846 (53,163)(270,510)
Cash and cash equivalents at beginning of period306,760 359,923 630,433 
Cash and cash equivalents at end of period$310,606 306,760 359,923 
1 Reclassified to conform with current presentation (see Note E). 2 Net cash provided by discontinued operations are not part of the cash flow reconciliation. See Notes to Consolidated Financial Statements, page 65.
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Years Ended December 31 (Thousands of dollars except share amounts)202020192018
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued
$— — — 
Common Stock – par $1.00, authorized 450,000,000 shares at December 31, 2020, 2019 and 2018, issued 195,100,628 at December 31, 2020, 195,089,269 shares at December 31, 2019 and 195,076,924 at December 31, 2018
Balance at beginning of year195,089 195,077 195,056 
Exercise of stock options12 12 21 
Balance at end of year195,101 195,089 195,077 
Capital in Excess of Par Value
Balance at beginning of year949,445 979,642 917,665 
Exercise of stock options, including income tax benefits(156)(182)(362)
Restricted stock transactions and other(33,649)(38,731)(33,920)
Stock-based compensation26,052 33,235 27,920 
Fair value increase in common controlled assets— (24,519)68,339 
Balance at end of year941,692 949,445 979,642 
Retained Earnings
Balance at beginning of year6,614,304 5,513,529 5,245,242 
Net income (loss) for the year attributable to Murphy(1,148,777)1,149,732 411,094 
Reclassification of certain tax effects from accumulated other comprehensive loss— — 30,237 
Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact— 114,712 — 
Cash dividends(95,989)(163,669)(173,044)
Balance at end of year5,369,538 6,614,304 5,513,529 
Accumulated Other Comprehensive Loss
Balance at beginning of year(574,161)(609,787)(462,243)
Foreign currency translation gains (losses), net of income taxes29,241 66,600 (145,022)
Retirement and postretirement benefit plans, net of income taxes(57,617)(35,979)29,110 
Deferred loss on interest rate hedge reclassified to interest expense,
net of income taxes		1,204 5,005 2,342 
Reclassification of certain tax effects to retained earnings— — (30,237)
Other— — (3,737)
Balance at end of year(601,333)(574,161)(609,787)
Treasury Stock
Balance at beginning of year(1,717,217)(1,249,162)(1,275,529)
Purchase of treasury shares— (499,924)— 
Awarded restricted stock, net of forfeitures26,556 31,869 26,367 
Balance at end of year – 41,502,003 of Common Stock in 2020, 42,153,908 shares of Common Stock in 2019, and 22,018,095 shares of Common Stock in 2018
(1,690,661)(1,717,217)(1,249,162)
Murphy Shareholders’ Equity4,214,337 5,467,460 4,829,299 
Noncontrolling Interest
Balance at beginning of year337,151 368,343 — 
Acquisition— — 359,951 
Acquisition closing adjustments— (6,604)— 
Net (loss) income attributable to noncontrolling interest(113,668)103,570 8,392 
Distributions to noncontrolling interest owners(43,673)(128,158)— 
Balance at end of year179,810 337,151 368,343 
Total Equity$4,394,147 5,804,611 5,197,642 
See Notes to Consolidated Financial Statements, page 65.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 60-64 of the Form 10-K report.
Note A – Significant Accounting Polices
NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas company that conducts its business through various operating subsidiaries.  The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide.  The Company sold its Malaysian assets in 2019 and they are reported as discontinued operations.  
PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries.  Undivided interests in oil and natural gas joint ventures are consolidated on a proportionate basis.  Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method.  Beginning in the fourth quarter of 2018, Murphy reports 100% of the sales volume, revenues, costs, assets and liabilities including the 20% noncontrolling interest (NCI), of MP GOM in accordance with accounting for noncontrolling interest as prescribed by ASC 810-10-45. Other investments are generally carried at cost.  All significant intercompany accounts and transactions have been eliminated.
REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities.  The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties.  Revenues from the production of oil and natural gas properties in which Murphy shares in the undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period.  Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well.  The company follows the sales method of accounting for these natural gas imbalances.  The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field.  At December 31, 2020 and 2019, the liabilities for natural gas balancing were immaterial.  Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues.  
CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.
MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity.  The Company does not have any investments classified as trading securities.  Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss.  Held-to-maturity securities are recorded at amortized cost.  Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security.  Dividend and interest income is recognized when earned.  Unrealized losses considered to be other than temporary are recognized in earnings.  The cost of securities sold is based on the specific identification method.  The fair value of investment securities is determined by available market prices. 
ACCOUNTS RECEIVABLE – At December 31, 2020 and 2019, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas and operating costs related to joint venture partners working interest share.  The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables.  The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers, joint venture partners, and historical write-off experience.  Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts.  The Company has not experienced any significant credit-related losses in the past three years.
INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and natural gas production operations.  Unsold crude oil production is carried in inventory at the lower of cost (applied on a first-in, first-out basis and includes costs incurred to bring the inventory to its existing condition), or market.  Materials and supplies inventories are valued at the lower of average cost or estimated market value and generally consist of tubulars and other drilling equipment.
PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures.  Leasehold acquisition costs are capitalized.  If proved reserves are found on undeveloped property, the leasehold cost is transferred to proved properties.  Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases.  Exploratory well costs are capitalized pending determination about whether proved
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note A – Significant Accounting Policies (Contd.)
reserves have been found.  In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately.  This is generally due to the need for major capital expenditure to produce and/or evacuate the hydrocarbon(s) found.  The determination of whether to make such capital expenditure is usually dependent on whether further exploratory or appraisal wells find a sufficient quantity of additional reserves.  The Company continues to capitalize exploratory well costs in Property, Plant and Equipment when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization.  Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred.  Development costs, including unsuccessful development wells, are capitalized.  Interest is capitalized on significant development projects that are expected to take one year or more to complete.
Oil and natural gas properties are evaluated by field for potential impairment.  Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable.  An impairment is recognized when there are indications that the estimated undiscounted future net cash flows of an asset are less than its carrying value.  If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. In 2020, declines in future oil and natural gas prices (principally driven by reduced commodity demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties and assets. In 2020, the Company recognized pretax noncash impairment charges of $1,206.3 million to reduce the carrying values at select properties. There were no impairments in 2019. As a result of management’s assessments during 2018, the Company recognized a pretax, noncash impairment charge of $20.0 million at select Midland properties. See also Note G for further discussion of impairment charges. 
The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset.  The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service.  The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates.  When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability.  The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset.  The Company reevaluates the adequacy of its recorded ARO liability at least annually.  Actual costs of asset retirements such as dismantling oil and natural gas production facilities and site restoration are charged against the related liability. See Note I. 
Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.
Depreciation and depletion of producing oil and natural gas properties are recorded based on units of production.  Unit rates are computed for unamortized development drilling and completion costs using proved developed reserves and acquisition costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on the availability of additional information. 
CAPITALIZED INTEREST– Interest associated with borrowings from third parties is capitalized on significant oil and natural gas development projects when the expected development period extends for one year or more.  Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, plant and equipment in the Consolidated Balance Sheets.  Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.
LEASES - At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets (related to Brunei) are presented on the Consolidated Balance Sheet within Assets held for sale with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt.
Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note A – Significant Accounting Policies (Contd.)
Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with the relevant expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations.
ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated.  If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability.  Environmental remediation liabilities have not been discounted for the time value of future expected payments.  Environmental expenditures that have future economic benefit are capitalized.
INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.  Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse.  The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors.  A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period.  
On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note J) and a provision for this impact has been recorded.  Deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested.  Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. 
The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized.  The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.
FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and former refining and marketing activities in the United Kingdom.  The U.S. dollar is the functional currency used to record all other operations.  Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings as part of Interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets.  Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings.  The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk.  Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions.  The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item.  A derivative that is not a highly effective hedge does not qualify for hedge accounting.  The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item.  The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in Accumulated other comprehensive loss in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings.  If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued, and the gain or loss recorded in Accumulated other comprehensive loss is recognized immediately in earnings.
FAIR VALUE MEASUREMENTS– The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.  Fair value is determined using various techniques depending on the availability of observable inputs.  Level 1 inputs include quoted prices in active markets for identical assets or liabilities.  Level 2 inputs include observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. See Note Q.
STOCK-BASED COMPENSATION
Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock.  The Company uses the Black-Scholes option pricing model for computing the fair value of equity-
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note A – Significant Accounting Policies (Contd.)
settled stock options.  The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price.  The Company uses both historical data and current information to support its assumptions.  Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years.  The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three-year vesting period.  The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period.  The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly.  Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known.
Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards.  Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units.  When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note K.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets.  Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated other comprehensive loss.  The remaining amounts in Accumulated other comprehensive loss include net actuarial losses and prior service (cost) credit. See Note L.
NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period.  Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares.  Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share.
USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans.  For public companies, the amendments in this ASU are effective for fiscal years ending after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company adopted the standard in the fourth quarter of 2020 and it did not have a material impact on its consolidated financial statements.
In March 2017, the FASB issued ASU 2017-7 requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual and interim periods beginning after December 15, 2017.  The Company elected to apply the practical expedient, which allows us to reclassify amounts disclosed previously in the retirement benefits note as the basis for applying retrospective presentation for comparative periods.  The Company adopted the standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.
Financial Instruments – Credit Losses. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)

permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Fair Value Measurement.  In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement.  The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019.  Implementation on a prospective or retrospective basis varies by specific disclosure requirement.  Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements.
Leases. In February 2016, the FASB issued an Accounting Standards Update (ASU) 2016-02 (Topic 842) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The company adopted the standard in the first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019.  The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in the initial recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to credit retained earnings of $114.7 million on its Consolidated Balance Sheets, with no material impact to its Consolidated Statements of Operations. See Note V for further information regarding the impact of the adoption of ASU 2016-02 on the Company’s financial statements.
Compensation – Stock Compensation.  In June 2018, the FASB issued an ASU 2018-07 which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees.  As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements.  The Company adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements.
In May 2017, the FASB issued ASU 2017-9 which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  The Company adopted this accounting standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.
Statement of Operations – Reporting Comprehensive Income.  In February 2018, the FASB issued ASU 2018-2, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act.  The Company elected to early adopt this accounting standard during the first quarter of 2018 and recorded discrete adjustments from accumulated other comprehensive income to retained earnings of $28.4 million related to retirement and postretirement obligations and $1.8 million related to the deferred loss on interest rate derivative hedges.  The adoption of this ASU will have no future impact.
Recent Accounting Pronouncements
Income Taxes.  In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU.   The Company adopted this guidance in the first quarter of 2021 and it did not have a material impact on its consolidated financial statements.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada.  Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.
For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.
U.S. - In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico.  Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.
Canada - In Canada, contracts are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.
In 2019, the Company made an immaterial reclassification to correct its financial statements to report transportation, gathering, and processing costs as a separate line item (previously reported net in revenue) in the Consolidated Statements of Operations and revised the 2018 period to reflect this presentation. There was no resultant change in net income attributable to Murphy.
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of Revenue within these geographies.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note C – Revenue from Contracts with Customers (Contd.)
For the years ended December 31, 2020, 2019, and 2018 the Company recognized $1,751.7 million, $2,817.1 million and $1,806.5 million, respectively, from contracts with customers for the continuing operations sales of oil, natural gas liquids and natural gas.
Years Ended December 31,
(Thousands of dollars)202020192018
Net crude oil and condensate revenue
United StatesOnshore$353,311 750,278 786,537 
                     Offshore940,265 1,477,816 417,527 
Canada    Onshore93,591 116,174 111,836 
Offshore71,495 159,254 176,291 
Other1,806 11,642 6,079 
Total crude oil and condensate revenue1,460,468 2,515,164 1,498,270 
Net natural gas liquids revenue
United States Onshore22,504 30,615 61,810 
 Offshore19,749 26,968 11,832 
Canada Onshore8,921 12,001 14,670 
Total natural gas liquids revenue51,174 69,584 88,312 
Net natural gas revenue
United States Onshore20,132 27,668 36,070 
Offshore49,300 46,259 17,559 
Canada   Onshore170,635 158,436 166,262 
Total natural gas revenue240,067 232,363 219,891 
Total revenue from contracts with customers 1
1,751,709 2,817,111 1,806,473 
Gain (loss) on crude contracts202,661 (856)(41,975)
Gain on sale of assets and other income 2
12,971 12,798 26,903 
Total revenue and other income$1,967,341 2,829,053 1,791,401 
1 Includes revenue attributable to noncontrolling interest in MP GOM, effective November 30, 2018.
2 Gain on sale of Malaysia operations of $985.4 million in 2019 is reported in discontinued operations. See Note E.
Contract Balances and Asset Recognition
As of December 31, 2020, and 2019, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $135.2 million and $186.8 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13 (see Note B), the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any upstream oil and natural gas sale contracts that have financing components as of December 31, 2020.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
Performance Obligations
The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer.  Judgment is required to determine whether some customers simultaneously receive and consume the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note C – Revenue from Contracts with Customers (Contd.)
benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy.
As of December 31, 2020, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:
Current Long-Term Contracts Outstanding at December 31, 2020
LocationCommodityEnd DateDescriptionApproximate Volumes
U.S.OilQ4 2021Fixed quantity delivery in Eagle Ford17,000 BOED
U.S.Natural Gas and NGLQ1 2023Deliveries from dedicated acreage in Eagle FordAs produced
CanadaNatural GasQ4 2021Contracts to sell natural gas at USD Index pricing10 MMCFD
CanadaNatural GasQ4 2022Contracts to sell natural gas at USD Index pricing7 MMCFD
CanadaNatural GasQ4 2022Contracts to sell natural gas at USD index fixed pricing20 MMCFD
CanadaNatural GasQ4 2023Contracts to sell natural gas at USD Index pricing25 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD Index pricing32 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at Alberta AECO fixed prices115 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD index fixed pricing15 MMCFD
CanadaNatural GasQ4 2026Contracts to sell natural gas at USD Index pricing49 MMCFD
Note D – Acquisitions
LLOG Transaction:
In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.
Under the terms of the transaction, Murphy paid cash consideration of $1,236.2 million and has an obligation to pay additional contingent consideration of up to $200.0 million in the event that certain revenue thresholds are exceeded between 2019 and 2022, and $50.0 million following first oil from certain development projects. The revenue threshold was not exceeded for the 2020 period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note D – Acquisition (Contd.)

(Thousands of dollars)LLOG
(Final)
Cash consideration paid $1,236,165 
Contingent consideration89,444 
Total purchase consideration1,325,609 
(Thousands of dollars)
Fair value of Property, plant and equipment1,356,185 
Other assets6,697 
Less:  Asset retirement obligations(37,273)
Total net assets$1,325,609 
Note E – Assets Held for Sale and Discontinued Operations
The following table presents the carrying value of the major categories of assets and liabilities that are reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2020. These include the King’s Quay Floating Production System (FPS) of $250.1 million, the Brunei exploration and production properties, and the Company’s office building in El Dorado, Arkansas. As of December 31, 2019 the balance represents assets and liabilities of the Brunei exploration and production properties and the U.K. refining and marketing operations.
(Thousands of dollars)
20202019
Current assets
Cash$10,185 25,185 
Accounts receivable— 4,834 
Inventories406 406 
Prepaid expenses and other— 1,882 
Property, plant, and equipment, net307,704 82,116 
Deferred income taxes and other assets9,441 9,441 
Total current assets associated with assets held for sale327,736 123,864 
Current liabilities
Accounts payable5,306 3,702 
Other accrued liabilities45 — 
Current maturities of long-term debt (finance lease)737 705 
Taxes payable1,510 1,411 
Asset retirement obligation261 240 
Long-term debt (finance lease)6,513 7,240 
Total current liabilities associated with assets held for sale14,372 13,298 
The Company has accounted for its former Malaysian exploration and production operations, along with its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations are presented in the following table.
(Thousands of dollars)
202020192018
Revenues 1
$4,090 1,364,943 854,251 
Costs and expenses
Lease operating expense
— 127,138 202,062 
Depreciation, depletion and amortization— 33,697 196,287 
Other costs and expenses (benefits)11,241 81,538 70,088 
Total income from discontinued operations before taxes(7,151)1,122,570 385,814 
Income tax expense— 58,083 135,466 
Income from discontinued operations$(7,151)1,064,487 250,348 
1 2019 includes a $985.4 million gain on sale of the Malaysia operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note F – Inventories
Inventories consisted of the following at December 31, 2020 and 2019.
December 31,
(Thousands of dollars)
20202019
Unsold crude oil$16,399 27,634 
Materials and supplies49,677 48,489 
Inventories$66,076 76,123 

Note G – Property, Plant, and Equipment
December 31, 2020December 31, 2019
(Thousands of dollars)CostNetCostNet
Exploration and production ¹$19,583,682 8,232,191 219,096,323 9,875,727 2
Corporate and other140,661 36,847 207,066 94,016 
Property, plant and equipment$19,724,343 8,269,038 19,303,389 9,969,743 
¹  Includes unproved mineral rights as follows:$649,704 530,194 508,526 121,163 
2  Includes $22,940 in 2020 and $24,698 in 2019 related to administrative assets and support equipment.
Divestments
In July 2019, the Company completed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $985.4 million was recorded as part of discontinued operations on the Consolidated Statement of Operations in 2019. Murphy was entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020, however the results were not achieved.
Acquisitions
In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.
Under the terms of the transaction, Murphy paid cash consideration of $1,236.2 million and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50.0 million following first oil from certain development projects. The revenue threshold was not exceeded for 2019 or 2020.
In 2018, a wholly owned subsidiary, Murphy Exploration & Production Company - USA, entered into a definitive agreement with Petrobras America Inc. (PAI), a subsidiary of Petrobras. The transaction was comprised of all of the Gulf of Mexico producing assets from Murphy and PAI with Murphy overseeing the operations.  Both companies contributed all their current producing Gulf of Mexico assets to MP Gulf of Mexico, LLC, a subsidiary of Murphy, which following closing of the transaction is owned 80% by Murphy and 20% by PAI. The transaction excluded Murphy’s exploration blocks. However, PAI’s blocks that hold deep exploration rights were part of the transaction. Murphy paid net cash consideration of $780.7 million, after adjustments provided for in the sale and purchase agreement. Additionally, PAI received a 20% interest in MP GOM and will earn an additional contingent consideration of up to $150.0 million if certain price and production thresholds are exceeded beginning in 2019 through 2025.  Also, Murphy agreed to carry $50.0 million of PAI development costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken. As of December 31, 2020, Murphy had funded $29.7 million of the carried interest.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note G – Property, Plant and Equipment (Contd.)
Impairments
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $1,206.3 million to reduce the carrying values of certain properties to their estimated fair values at the time of impairment.
During 2018, declines in future oil and natural gas prices led to impairments in certain of the Company’s producing properties. During 2018, as a result declines in future oil and natural gas prices, the Company recorded pretax noncash impairment charges of $20.0 million to reduce the carrying values of certain Midland properties to their estimated fair values at the time of impairment.
The following table reflects the recognized impairments for the three years ended December 31, 2020.
December 31,
(Thousands of dollars)202020192018
U.S.$1,152,515 — 20,000 
Other Foreign39,709 — — 
Corporate14,060 — — 
$1,206,284 — 20,000 
Exploratory Wells
Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
At December 31, 2020, 2019 and 2018, the Company had total capitalized drilling costs pending the determination of proved reserves of $181.6 million, $217.3 million and $207.9 million, respectively.  The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2020.
(Thousands of dollars)
202020192018
Beginning balance at January 1$217,326 207,855 155,103 
Additions pending the determination of proved reserves3,999 83,712 59,487 
Reclassifications to proved properties based on the determination of proved reserves
— (61,096)(2,214)
Capitalized exploration well costs charged to expense(39,709)(13,145)(4,521)
Ending balance at December 31$181,616 217,326 207,855 
The capitalized well costs charged to expense during 2020 represent a charge for asset impairments (see above). The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. The capitalized well costs charged to expense during 2018 included the Julong East well in Block CA-1, offshore Brunei in which further development of the well has not been sanctioned by the operator and the contract term for development sanctions was reached.  This well was originally drilled in 2012.
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs has been capitalized.  The projects are aged based on the last well drilled in the project.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note G – Property, Plant and Equipment (Contd.)
202020192018
(Thousands of dollars)
AmountNo. of
Wells		No. of
Projects		AmountNo. of
Wells		No. of
Projects		AmountNo. of
Wells		No. of
Projects
Aging of capitalized well costs:
Zero to one year$— ——$63,409 55$61,096 11
One to two years54,220 55— ——40,523 32
Two to three years— ——27,396 1—5,208 11
Three years or more127,396 6— 126,521 5—101,028 41
$181,616 115$217,326 115$207,855 95
Of the $181.6 million of exploratory well costs capitalized more than one year at December 31, 2020, $89.7 million is in Vietnam, $45.9 million is in the U.S., $25.6 million is in Brunei, $15.5 million is in Mexico, and $4.8 million is in Canada. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Note H – Financing Arrangements and Debt
As of December 31, 2020, the Company has a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At December 31, 2020, the Company had $200.0 million outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF.  At December 31, 2020, the interest rate in effect on borrowings under the facility would have been 1.84%.  At December 31, 2020, the Company was in compliance with all covenants related to the RCF.

In May 2019, the Company entered into a $500 million term loan credit facility (the New Term Credit Facility). The New Term Credit Facility was a senior unsecured guaranteed facility with an original maturity date of December 2, 2019. The covenants within the New Term Credit Facility were substantially consistent with those in the Company’s revolving credit facility (see RCF above), and borrowings under the New Term Credit Facility bore interest at comparable rates to those incurred under the 2018 facility. In July 2019, the Company closed the previously announced Malaysia divestiture, repaid and terminated the New Term Credit Facility.

In November 2019, the Company sold $550 million of new notes that bear interest at a rate of 5.875% and mature on December 1, 2027. The Company incurred transaction costs of $7.4 million on the issuance of these new notes. The Company will pay interest semi-annually on June 1 and December 1 of each year, beginning June 1, 2020. The proceeds of the $550 million notes were used to repurchase and cancel $239.7 million of the Company’s 4.00% notes due 2022 and $281.6 million of the Company’s 4.45% notes due 2022 (originally issued as 3.70% notes due 2022, see table footnote below) (collectively the 2022 Notes) during November and December. The cost of the debt extinguishment of $32.1 million is included in Interest expense, net on the Consolidated Statement of Operations for the year ended December 31, 2019. The cash costs of $26.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2019.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note H – Financing Arrangements and Long-Term Debt (Contd.)
December 31,
(Thousands of dollars)20202019
Notes payable
4.00% notes, due June 2022
$259,291 260,251 
4.95% notes, due December 2022 ¹
317,067 318,417 
6.875% notes, due August 2024
542,428 550,000 
5.75% notes, due August 2025
548,675 550,000 
5.875% notes, due December 2027
543,249 550,000 
7.05% notes, due May 2029
250,000 250,000 
6.375% notes, due December 2042 ¹
349,000 350,000 
Total notes payable2,809,710 2,828,668 
Unamortized debt issuance cost and discount on notes payable(21,643)(25,287)
Total notes payable, net of unamortized discount2,788,067 2,803,381 
Senior Unsecured Revolving Credit Facility200,000 — 
Total long-term debt$2,988,067 2,803,381 
1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.
The amount of long-term debt repayable over each of the next five years and thereafter are as follows:  nil in 2021, $576.4 million in 2022, $200.0 million in 2023, $542.4 million in 2024, $548.7 million in 2025 and $1.14 billion thereafter.
Note I – Asset Retirement Obligations
The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2020 and 2019 are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.
A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2020 and 2019 is shown in the following table.
(Thousands of dollars)20202019
Balance at beginning of year$865,109 800,117 
Accretion expense42,136 40,506 
Liabilities incurred14,736 14,759 
Liabilities assumed from acquisitions— 64,810 
Revisions of previous estimates(70,098)(34,371)
Liabilities settled(4,816)(25,544)
Liabilities associated with assets held for sale(21)(240)
Changes due to translation of foreign currencies2,910 5,072 
Balance at end of year849,956 865,109 
Current portion of liability at end of year ¹(33,648)(39,315)
Noncurrent portion of liability at end of year$816,308 825,794 
1 Included in Other accrued liabilities on the Consolidated Balance Sheet.
The estimation of future ARO is based on a number of assumptions requiring professional judgment.  The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as:  prices for oil field services, technological changes, governmental requirements and other factors.
Liabilities assumed in 2019, primarily represent obligations assumed as part of the LLOG acquisition (see Note D).



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Note J – Income Taxes
The components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows.
(Thousands of dollars)
202020192018
Income (loss) from continuing operations before income taxes
United States$(1,407,598)282,199 14,907 
Foreign(141,437)(78,701)28,095 
Total$(1,549,035)203,498 43,002 
Income tax expense (benefit)
U.S. Federal – Current$(10,627)— (9,765)
    – Deferred(249,253)30,598 (131,200)
Total U.S. Federal(259,880)30,598 (140,965)
State(8,413)5,139 3,299 
Foreign – Current(5,072)(17,823)61,257 
– Deferred(20,376)(3,231)(49,727)
Total Foreign(25,448)(21,054)11,530 
Total$(293,741)14,683 (126,136)
The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.
(Thousands of dollars)
202020192018
Income tax expense (benefit) based on the U.S. statutory tax rate
$(325,299)42,735 9,031 
Alberta tax rate reduction and tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform)
— (17,019)(135,700)
Foreign income (loss) subject to foreign tax rates different than the U.S.statutory rate(3,791)(1,122)5,822 
State income taxes, net of federal benefit
(6,646)4,060 2,607 
U.S. tax benefit on certain foreign upstream investments
— (14,975)(14,702)
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures
7,707 10,927 3,283 
Tax effect on income attributable to noncontrolling interest23,712 (21,750)(1,753)
Other, net10,576 11,827 5,276 
Total$(293,741)14,683 (126,136)
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Note J – Income Taxes (Contd.)
An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2020 and 2019 showing the tax effects of significant temporary differences follows.
(Thousands of dollars)
20202019
Deferred tax assets
Property and leasehold costs$95,141 233,351 
Liabilities for dismantlements28,475 78,361 
Postretirement and other employee benefits128,281 125,250 
Alternative minimum tax— 9,765 
U. S. net operating loss589,067 495,252 
Investment in partnership65,216 — 
Other deferred tax assets112,685 66,795 
Total gross deferred tax assets1,018,865 1,008,774 
Less valuation allowance(106,448)(103,113)
Net deferred tax assets912,417 905,661 
Deferred tax liabilities
Deferred tax on undistributed foreign earnings(5,000)(5,000)
Accumulated depreciation, depletion and amortization(665,255)(938,614)
Investment in partnership— (14,250)
Other deferred tax liabilities(27,250)(25,708)
Total gross deferred tax liabilities(697,505)(983,572)
Net deferred tax (liabilities) assets$214,912 (77,911)
In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for deferred tax assets relate primarily to tax assets arising in foreign tax jurisdictions that in the judgment of management at the present time are more likely than not to be unrealized. The valuation allowance increased $3.3 million in 2020, related all to non-U.S. items. Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset.
The Company has an estimated U.S. net operating loss of $2.8 billion at year-end 2020 with a corresponding deferred tax asset of $589.1 million.  The Company believes the U.S. net operating loss being carried forward will more likely than not be utilized in future periods prior to expirations in 2036 and 2037.
Other Information
Currently the Company considers $100 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $5 million liability.  At December 31, 2020, $1.4 billion of past foreign earnings are considered permanently reinvested.  The Company closely and routinely monitors these reinvestment positions considering underlying facts and circumstances pertinent to our business and the future operation of the company.
Uncertain Income Tax Positions
The financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon ultimate settlement.  If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50% likely of being realized upon ultimate settlement.  Liabilities associated with uncertain income tax positions are included in Deferred credits and other liabilities in the Consolidated Balance Sheets.  A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note J – Income Taxes (Contd.)
(Thousands of dollars)
202020192018
Balance at January 1$2,538 2,903 3,437 
Additions for tax positions related to current year3,042 456 454 
Settlements due to lapse of time— (821)(988)
Settlements with taxing authorities(2,748)— — 
Balance at December 31$2,832 2,538 2,903 
All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change.  The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense.  The Company also had other recorded liabilities as of December 31, 2020, 2019 and 2018 for interest and penalties of $0.3 million, $0.1 million and $0.2 million, respectively, associated with uncertain tax positions.  Income tax expense for the years ended December 31, 2020, 2019 and 2018 included net benefits for interest and penalties of $0.1 million, $0.1 million and $0.1 million, respectively, associated with uncertain tax positions.
In 2021, the Company currently expects to add between $0.2 million and $1.0 million to the provision for uncertain tax positions.  Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2021.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As of December 31, 2020, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows:  United States – 2016; Canada – 2016; Malaysia – 2014; and United Kingdom – 2018. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.
The Tax Cuts and Jobs Act and The Coronavirus Aid, Relief, and Economic Security Act
On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act).  For the year ended December 31, 2017, the Company recorded a provisional tax expense of $274 million directly related to the impacts of the 2017 Tax Act.  The charge included the impact of a deemed repatriation of foreign earnings and the re-measurement of deferred tax assets and liabilities.  During 2018, the Company completed the accounting for the income tax effects related to the 2017 Tax Act. The Company revised the provisional amount recorded in 2017 and recognized a favorable income tax adjustment of $135.7 million primarily related to the reinstatement of a deferred tax asset for 2017 net operating losses, which in 2017 was assumed utilized against the deemed repatriation.  This reinstatement followed April 2, 2018 Internal Revenue Service guidance which allowed the Company to preserve the 2017 tax net operating loss as a carryforward. In the fourth quarter of 2020, under the provisions of the Coronavirus Aid, Relief, and Economic Security (CARES) Act, which was enacted earlier in the year, the Company received a refund of its remaining outstanding AMT credit balance of approximately $18.5 million.












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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note K – Incentive Plans
Murphy utilizes cash-based and/or share-based incentive awards to supplement normal salaries as compensation for executive management and certain employees.  For share-based awards that qualify for equity accounting, costs are recognized as an expense in the Consolidated Statements of Operations using a grant date fair value-based measurement method over the periods that the awards vest.  For share-based awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined.  Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.
At the Company’s annual stockholders’ meeting held on May 13, 2020, shareholders approved replacement of the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) with the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). The 2020 Long-Term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees in the same form as the 2018 Long-Term Plan. The new plan can be found in the Company’s Definitive Proxy statement (Definitive 14A) dated March 30, 2020. All awards on or after May 13, 2020 will be made under the 2020 Long-Term Plan.
The Company currently has outstanding incentive awards issued to certain employees under the 2017 Annual Incentive Plan, the 2012 Long-Term Plan and the 2018 Long-Term Plan.  The 2017 Annual Incentive Plan authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees.  Cash awards under the 2017 Annual Incentive Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. 
The 2020 Long-Term Plan, the 2018 Long-Term Plan and the 2012 Long-term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2020 Long-Term Plan expires in 2030.  A total of 5 million and 6.75 million shares are issuable during the life of the 2020 Long-Term Plan and the 2018 Long-Term Plan. There have been no awards granted from the 2020 Long Term Plan to date. In 2018, the Company’s shareholders approved the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The company currently has outstanding incentive awards issued to directors under the 2013 NED Plan and the 2018 NED Plan.
The Company generally expects to issue treasury shares to satisfy future stock option exercises and vesting of restricted stock and restricted stock units.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
(Thousands of dollars)
202020192018
Compensation charged against income (loss) before income tax benefit$24,812 50,170 34,467 
Related income tax benefit recognized in income2,672 7,389 4,383 
As of December 31, 2020, there were $42.6 million in compensation costs to be expensed over approximately the next five years related to unvested share-based compensation arrangements granted by the Company.  Employees receive net shares, after applicable withholding obligations, upon each stock option exercise and restricted stock award.  Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were immaterial for the years ended December 31, 2020, 2019 and 2018.
Equity-Settled Awards
STOCK OPTIONS – In 2018, the Company ceased the inclusion of stock options and stock appreciation rights as a part of the long-term incentive compensation mix. 
Previously, the Committee fixed the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixed the option term at no more than seven years from such date.  Each option granted to date under the 2012 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant.  Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years.  For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note K – Incentive Plans (Contd.)
The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table.  Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock.  The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior.  The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant.
Changes in stock options outstanding during the last three years are presented in the following table.
Number of
Shares		Average
Exercise
Price
Outstanding at December 31, 20174,901,269 $45.74 
Exercised(72,000)17.57 
Forfeited(834,674)53.36 
Outstanding at December 31, 20183,994,595 44.66 
Exercised(57,500)17.57 
Forfeited(1,016,685)48.29 
Outstanding at December 31, 20192,920,410 43.93 
Exercised(47,000)17.57 
Forfeited(825,010)54.85 
Outstanding at December 31, 20202,048,400 40.14 
Exercisable at December 31, 20173,197,269 $54.22 
Exercisable at December 31, 20183,182,345 49.10 
Exercisable at December 31, 20192,694,410 43.51 
Exercisable at December 31, 20202,048,400 37.88 
Additional information about stock options outstanding at December 31, 2020 is shown below.
Options OutstandingOptions Exercisable
Range of Exercise
Prices per Option		No. of
Options		Avg. Life
Remaining
in Years		Aggregate
Intrinsic
Value		No. of
Options		Avg. Life
Remaining
in Years		Aggregate
Intrinsic
Value
$17.00 to $30.99
984,500 2.5$— 984,500 2.5$— 
$31.00 to $50.99
655,000 1.1— 655,000 1.1— 
$51.00 to $65.00
408,900 0.1— 408,900 0.1— 
2,048,400 1.6$— 2,048,400 1.6$— 
The total intrinsic value of options exercised during 2020 was $0.5 million.  Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise.  Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock.
PERFORMANCE-BASED RESTRICTED STOCK UNITS – Performance-based restricted stock units (PSUs) to be settled in Common shares were granted in 2020 and 2019 under the 2018 Long-Term Plan and 2018 under the 2012 Long-Term Plan.  Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period.  Additional shares may be awarded if performance objectives are exceeded.  If performance goals are not met, PSUs will not vest, but recognized compensation cost associated with the stock award would not be reversed.  For PSUs, the performance conditions are based on the Company’s total shareholder return (80% weighting) and the EBITDA divided by Average Capital Employed (ACE) metric (20% weighting) for PSU awards beginning in 2020, over the performance period compared to an industry peer group of companies.  During the performance period, PSUs are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death.  Termination for these three reasons will lead to a pro rata award of amounts earned.  No dividends are paid nor do voting rights exist on awards of PSUs prior to their settlement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note K – Incentive Plans (Contd.)
Changes in PSUs outstanding for each of the last three years are presented in the following table.
(Number of stock units)
202020192018
Outstanding at beginning of year2,129,733 1,660,417 1,187,921 
Granted999,700 957,600 905,500 
Vested and issued(429,194)(331,917)(311,866)
Forfeited(492,810)(156,367)(121,138)
Outstanding at end of year2,207,429 2,129,733 1,660,417 
The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model.  Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period.  The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group.  The assumptions used in the valuation of the performance awards granted in 2020, 2019 and 2018 are presented in the following table.
202020192018
Fair value per share at grant date21.51$28.09
$22.99 - $30.56
Assumptions
Expected volatility39.00%46.00%48.00%
Risk-free interest rate1.40%2.50%2.30%
Stock beta0.8641.0371.103
Expected life3.0 years3.0 years3.0 years
TIME-BASED RESTRICTED STOCK UNITS – Time-based restricted stock units (RSUs) have been granted to the Company’s Non-Employee Directors (NED) under the 2013 NED Plan and 2018 NED Plan and to certain employees under the 2012 Long-Term Plan and 2018 Long-Term Plan. The RSUs granted under the 2012 Long-Term Plan, the 2013 NED Plan and the 2018 Long-Term Plan vest on the third anniversary of the date of grant. Under the 2018 NED Plan, the RSUs granted in 2019 vest on the third anniversary of the date of grant and the RSUs granted in 2020 vest on the first anniversary of the date of grant. The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $22.59 to $21.68 per share in 2020, $21.68 to $28.16 per share in 2019, and $25.69 to $28.43 per share in 2018.
Changes in RSUs outstanding for each of the last three years are presented in the following table.
(Number of share units)
202020192018
Outstanding at beginning of year1,535,080 1,538,854 1,035,980 
Granted446,848 409,692 823,803 
Vested and issued(271,285)(275,738)(233,456)
Forfeited(327,600)(137,728)(87,473)
Outstanding at end of year1,383,043 1,535,080 1,538,854 
Cash-Settled Awards
The Company has granted stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SARs), Performance-based restricted stock units (CPSUs), Time-based restricted stock units (CRSUs) and Phantom units.
SAR awards have terms similar to stock options. CPSU terms are similar to other performance-based restricted stock awards (PSUs). CRSUs generally settle on the third anniversary of the date of grant.  Phantom units generally settle three to five years from date of grant.  Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares.  Total expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $1.5 million in 2020, $16.9 million in 2019 and $6.5 million in 2018.
The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees.  These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives.  Compensation expense of $9.8 million, $34.1 million and $30.0 million was recorded in 2020, 2019 and 2018, respectively, for these plans.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Employee and Retiree Benefit Plans
PENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees.  All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan.  All U.S. tax qualified plans meet the funding requirements of federal laws and regulations.  Contributions to foreign plans are based on local laws and tax regulations.  The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees.  The health care benefits are contributory; the life insurance benefits are noncontributory.
Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business.  No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy.
GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through accumulated other comprehensive loss.
On May 6, 2020, the Company announced that it was closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction in force. The Company elected the use of a practical expedient to perform the pension remeasurement as of May 31, 2020, which resulted in an increase in our pension and other postretirement benefit liabilities of $63.0 million (as of May 31, 2020) due to a lower discount rate and lower plan assets compared to December 31, 2019.
The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2020 and 2019 and a statement of the funded status as of December 31, 2020 and 2019.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note L – Employee and Retiree Benefit Plans (Contd.)


Pension
Benefits		Other
Postretirement
Benefits
(Thousands of dollars)
2020201920202019
Change in benefit obligation
Obligation at January 1$883,269 777,645 108,401 94,779 
Service cost7,967 7,964 1,373 1,559 
Interest cost21,127 27,835 2,626 3,864 
Participant contributions— 11 2,225 1,930 
Actuarial loss (gain)107,258 103,374 3,758 10,503 
Medicare Part D subsidy— — 243 234 
Exchange rate changes7,074 7,687 13 30 
Benefits paid(46,066)(41,247)(4,238)(4,498)
Curtailments(7,596)— (6,023)— 
Special termination benefits8,434 — — — 
Obligation at December 31981,467 883,269 108,378 108,401 
Change in plan assets
Fair value of plan assets at January 1547,484 487,094 — — 
Actual return on plan assets48,115 70,893 — — 
Employer contributions30,178 25,915 1,770 2,333 
Participant contributions— 11 2,225 1,930 
Medicare Part D subsidy— — 243 234 
Exchange rate changes7,009 7,328 — — 
Benefits paid(46,066)(41,247)(4,238)(4,497)
Other— (2,510)— — 
Fair value of plan assets at December 31586,720 547,484 — — 
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets4,572 5,353 — — 
Other accrued liabilities(9,468)(8,810)(5,298)(5,234)
Deferred credits and other liabilities(389,851)(332,328)(103,080)(103,167)
Fund Status and net plan liability recognized at December 31$(394,747)(335,785)(108,378)(108,401)
At December 31, 2020, amounts included in Accumulated other comprehensive loss (AOCL) in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.
(Thousands of dollars)
Pension
Benefits		Other
Postretirement
Benefits
Net actuarial gain (loss)$(313,317)3,707 
Prior service cost(2,731)— 
$(316,048)3,707 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note L – Employee and Retiree Benefit Plans (Contd.)


The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.
Projected
Benefit Obligations		Accumulated
Benefit Obligations		Fair Value
of Plan Assets
(Thousands of dollars)
202020192020201920202019
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets$762,134 688,249 753,475 676,177 564,238 525,108 
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets
201,372 177,999 198,792 171,934 — — 
Unfunded other postretirement plans108,378 108,401 108,378 108,401 — — 
The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2020.
Pension BenefitsOther
Postretirement Benefits
(Thousands of dollars)
202020192018202020192018
Service cost$7,967 7,964 8,994 1,373 1,559 1,965 
Interest cost21,127 27,835 26,168 2,626 3,864 3,427 
Expected return on plan assets(24,316)(25,719)(29,236)— — — 
Amortization of prior service cost (credit)640 964 1,021 — — (38)
Recognized actuarial loss22,828 14,106 21,893 (31)(193)— 
Net periodic benefit expense28,246 25,150 28,840 3,968 5,230 5,354 
Termination benefits expense8,434 — — — — — 
Curtailment expense586 — — (1,825)— — 
Total net periodic benefit expense$37,266 25,150 28,840 2,143 5,230 5,354 
The preceding tables in this note include the following amounts related to foreign benefit plans.
Pension
Benefits		Other
Postretirement
Benefits
(Thousands of dollars)
2020201920202019
Benefit obligation at December 31$230,101 209,923 492 387 
Fair value of plan assets at December 31221,463 197,965 — — 
Net plan liabilities recognized(8,638)(11,957)492 387 
Net periodic benefit expense (benefit)437 (933)46 147 
The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2020 and 2019 and net periodic benefit expense for 2020 and 2019.
Benefit ObligationsNet Periodic Benefit Expense
Pension
Benefits		Other
Postretirement
Benefits		Pension
Benefits		Other
Postretirement
Benefits
December 31,December 31,YearYear
20202019202020192020201920202019
Discount rate2.25 %3.85 %2.50 %3.42 %2.75 %3.35 %3.16 %4.42 %
Expected return on plan assets4.43 %5.05 %— — 4.43 %5.05 %— — 
Rate of compensation increase3.04 %3.28 %— — 3.28 %3.52 %— — 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note L – Employee and Retiree Benefit Plans (Contd.)


The discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country.  Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans.  The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country.  Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics.  Expected compensation increases are based on anticipated future averages for the Company.
Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.
(Thousands of dollars)
Pension
Benefits		Other
Postretirement
Benefits
2021$45,903 5,298 
202247,205 5,268 
202346,996 5,251 
202447,589 5,224 
202547,346 5,182 
2026-2031242,700 25,954 
For purposes of measuring postretirement benefit obligations at December 31, 2020, the future annual rates of increase in the cost of health care were assumed to be 6.2% for 2020 decreasing each year to an ultimate rate of 4.5% in 2038 and thereafter.
During 2020, the Company made contributions of $30.5 million to its domestic defined benefit pension plans and $1.8 million to its domestic postretirement benefits plan.  During 2021, Company currently expects to make contributions of $31.3 million to its domestic defined benefit pension plans, $5.3 million to its foreign defined benefit pension plans and $5.3 million to its domestic postretirement benefits plan.
Plan Investments – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan.  The Statement specifies that all assets will be held in a Trust sponsored by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee).  Members of the Committee are appointed by the Chief Executive Officer of Murphy.  The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement.  The investment goals call for a portfolio of assets consisting of equity, fixed income and cash equivalent securities.  The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation.  The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities.  The Company believes that over time a balanced to slightly heavier weighting of the portfolio in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans.
Generally, no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100.0 million.  Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets.  Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity.  The fixed income portfolio should not exceed an average maturity of 11 years.  The portfolio may include investment grade corporate bonds, bond issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds.  The Committee routinely reviews the investment performance of Investment Managers.
For the U.K. retirement plan, trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees.  The trustees have hired Hewitt Risk Management Services Limited (the Manager) as fiduciary investment manager of the plan’s assets. The trustees have adopted a de-risking strategy which permits the Manager discretion to vary the investment allocation as needed to meet a target return. The target return is reduced over time as pre-determined funding level triggers are met in proportion to pension liability changes.  As of December 31, 2020, one of seven funding level triggers have been met which led to a reduction in growth assets to more low-risk assets. The plan primarily invests in two funds, the Delegated Growth Fund (DGF) and the Delegated Liability Fund (DLF). The DGF is diversified by style, strategy and asset
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note L – Employee and Retiree Benefit Plans (Contd.)


class by investing with underlying funds that may include equity funds, fixed income funds, debt funds, currency funds, hedge funds, fund of hedge funds and other collective investment schemes covering a broad range of asset classes and strategies.  The DLF aims to provide returns in line with the liabilities of typical pension plans on an exposure basis in the relevant tenures and instruments (long/short, real/nominal).  The DLF also holds cash as collateral for the leveraged positions along with small working cash balances to facilitate daily management of payments and receipts within the plan.  The trustee routinely reviews the investment performance of the plan.
For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets.  A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio.  The Policy permits assets to be invested in various Canadian and foreign equity securities, various fixed income securities, real estate, natural resource properties or participation rights and cash.  The objective for plan investments is to achieve a total rate of return equal to the long-term interest rate assumption used for the going-concern actuarial funding valuation.
The following table provides the asset allocation of each plan on December 31, 2020.
Allocation of Plan Assets
Domestic PlanCanadian PlanU.K. Plan
TargetAllocation atTargetAllocation atTargetAllocation at
AllocationDecember 31, 2020AllocationDecember 31, 2020AllocationDecember 31, 2020
Equity securities
40-70%
56.0%
—%
31.0%N/A65.0%
Fixed income securities
28-60%
28.0%
98%
68.0%N/A11.7%
Alternatives
0-18%
11.4%—%—%N/A18.0%
Cash and equivalents
0-15%
4.6%
2%
1.0%N/A5.3%
The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2020 and 2019 are presented in the following table.
December 31,
20202019
Equity securities58.1 %54.9 %
Fixed income securities24.0 26.2 
Alternatives13.2 17.3 
Cash equivalents4.7 1.6 
100.0 %100.0 %
The Company’s weighted average expected return on plan assets was 4.70% in 2020 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans.  The 4.70% expected return was based on a weighted average expected future equity securities return of 3.90% and a fixed income securities return of 0.80%. There is also an average expected investment expense of 0.60%. Over the last 10 years, the return on funded retirement plan assets has averaged 7.55%.
At December 31, 2020, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.
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Note L – Employee and Retiree Benefit Plans (Contd.)


Fair Value Measurements Using
(Thousands of dollars)
Fair Value at December 31,
2020		Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)
Domestic Plans
Equity securities:
U.S. core equity$67,326 67,326 — — 
U.S. small/midcap28,953 28,953 — — 
Hedged funds and other alternative strategies42,040 — — 42,040 
International commingled trust fund76,095 987 55,433 19,675 
Emerging market commingled equity fund32,058 10,480 21,578 — 
Fixed income securities:
U.S. fixed income92,668 — 92,668 — 
International commingled trust fund9,456 — 9,456 — 
Cash and equivalents16,661 16,661 — — 
Total Domestic Plans365,257 124,407 179,135 61,715 
Foreign Plans
Equity securities funds74,393 — 74,393 — 
Fixed income securities funds45,240 — 45,240 — 
Diversified pooled fund54,871 — 54,871 — 
Other35,970 — — 35,970 
Cash and equivalents10,989 — 10,989 — 
Total Foreign Plans221,463 — 185,493 35,970 
Total$586,720 124,407 364,628 97,685 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note L – Employee and Retiree Benefit Plans (Contd.)


At December 31, 2019, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.
Fair Value Measurements Using
(Thousands of dollars)
Fair Value at December 31,
2019		Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)
Domestic Plans
Equity securities:
U.S. core equity$63,169 63,169 — — 
U.S. small/midcap26,062 26,062 — — 
Hedged funds and other alternative strategies58,864 — — 58,864 
International commingled trust fund73,783 924 55,798 17,061 
Emerging market commingled equity fund25,911 8,011 17,900 — 
Fixed income securities:
U.S. fixed income88,525 — 88,525 — 
International commingled trust fund8,720 — 8,720 — 
Cash and equivalents4,485 4,485 — — 
Total Domestic Plans349,519 102,651 170,943 75,925 
Foreign Plans
Equity securities funds68,878 — 68,878 — 
Fixed income securities funds46,582 — 46,582 — 
Diversified pooled fund42,582 — 42,582 — 
Other35,661 — — 35,661 
Cash and equivalents4,262 — 4,262 — 
Total Foreign Plans197,965 — 162,304 35,661 
Total$547,484 102,651 333,247 111,586 
The definition of levels within the fair value hierarchy in the tables above is included in Note Q – Assets and Liabilities Measured at Fair Value .
For domestic plans, U.S. core and small/midcap equity securities are valued based on daily market prices as quoted on national stock exchanges or in the over-the-counter market.  Hedge funds and other alternative strategies funds consist of three investments.  One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthly based on net asset value and permits withdrawals semi-annually after a 90-day notice, and the third investment is also valued monthly based on net asset values and has a two-year lock-up period and a 95-day notice following the lock-up period.  International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges.  The emerging market commingled equity fund is valued monthly based on net asset value.  These commingled equity funds can be withdrawn monthly and have a 10-day notice period.  U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset values.  International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values.  The fixed income emerging market mutual fund is valued daily based on net asset value.  For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values.  Fixed income securities funds are U.K. securities valued daily at net asset values.  The diversified pooled fund is valued daily at net asset value and contains a combination of Canadian and foreign equity securities, Canadian fixed income securities and cash.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note L – Employee and Retiree Benefit Plans (Contd.)


The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:
(Thousands of dollars)
Hedged Funds and Other
Alternative Strategies
Total at December 31, 2018$35,029 
Actual return on plan assets:
Relating to assets held at the reporting date20,811 
Purchases, sales and settlements55,746 
Total at December 31, 2019111,586 
Actual return on plan assets:
Relating to assets held at the reporting date5,694 
Purchases, sales and settlements(19,595)
Total at December 31, 2020$97,685 
THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay.  The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6%.  Amounts charged to expense for the Company’s match to these plans were $6.6 million in 2020, $8.4 million in 2019 and $5.2 million in 2018.
Note M – Financial Instruments and Risk Management
DERIVATIVE INSTRUMENTS – Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL and amortized to Interest expense over the life of the related liability.
Commodity Purchase Price Risks
The Company is subject to commodity price risk related to products it produces and sells.  During the last three years, the Company had West Texas Intermediate (WTI) crude oil price swap financial contracts to economically hedge a portion of its United States production.  Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.
At December 31, 2020, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2021 at an average price of $42.77 and 15,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2022 at an average price of $44.27.
At December 31, 2019, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2020 at an average price of $56.42.
At December 31, 2020 and 2019, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.  
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note M – Financial Instruments and Risk Management (Contd.)

December 31, 2020December 31, 2019
(Thousands of dollars)
Asset (Liability) DerivativesAsset (Liability) Derivatives
Type of Derivative Contract
Balance Sheet LocationFair ValueBalance Sheet Location Fair Value
CommodityAccounts receivable$13,050 Accounts payable$(33,364)
Accounts payable(89,842)
Deferred credits and other liabilities(12,833)
For the years ended December 31, 2020, 2019, and 2018, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.
Gain (Loss)
(Thousands of dollars)
Year Ended December 31,
Type of Derivative ContractStatement of Operations Locations202020192018
Commodity(Loss) gain on crude contracts$202,661 (856)(41,975)
Interest Rate Risks
Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During the years ended December 31, 2020 and 2019, $1.5 million and $6.3 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statements of Operations as a result of normal amortization in 2020 and the early extinguishment of a portion of the deferred loss in 2019 (see Note H). During the year ended December 31, 2018, $3.0 million of the deferred loss was recognized in Interest expense in the Consolidated Statements of Operations. The remaining loss (net of tax) deferred on these matured contracts at December 31, 2020 was $1.7 million, which is recorded, net of income taxes of $0.4 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheets.  The Company expects to charge approximately $1.5 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during 2021.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  The Company had no foreign currency exchange short-term derivative instruments outstanding as of December 31, 2020 and 2019.  
CREDIT RISKS – The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments.  Trade receivables arise mainly from sales of oil and natural gas in the U.S. and Canada, and cost sharing amounts of operating and capital costs billed to partners for properties operated by Murphy.  The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made.  The combination of these evaluations and the large number of customers tends to limit the risk to any one customer. Cash balances and cash equivalents are held with several major financial institutions, which limit the Company’s exposure to credit risk for its cash assets. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the majority of transactions are major financial institutions.
Note N – Earnings Per Share
Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for each of the three years ended December 31, 2020.  The following table reconciles the weighted-average shares outstanding used for these computations.
(Weighted-average shares)
202020192018
Basic method153,507,109 163,992,427 172,974,491 
Dilutive stock options 1 
— 820,001 1,234,274 
Diluted method153,507,109 164,812,428 174,208,765 
1 Due to a net loss recognized by the Company for the year ended December 31, 2020, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
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Note N – Earnings per Share (Contd.)
The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2020, but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.
202020192018
Antidilutive stock options excluded from diluted shares2,246,532 2,974,401 3,942,296 
Weighted average price of these options$39.67 $45.26 $46.77 
Note O – Other Financial Information
GAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $(0.9) million in 2020, $(6.0) million in 2019 and $16.1 million in 2018.
Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2020 as shown in the following table.
(Thousands of dollars)
202020192018
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹$164,613 (232,037)(30,212)
(Increase) decrease in inventories5,953 10,258 16,794 
(Increase) decrease in prepaid expenses7,178 4,650 (10,011)
Increase (decrease) in accounts payable and accrued liabilities ¹(208,740)196,773 8,784 
Increase (decrease) in income taxes payable(1,031)3,469 (1,458)
Net (increase) decrease in noncash operating working capital$(32,027)(16,887)(16,103)
Supplementary disclosures:
Cash income taxes paid, net of refunds$(44,715)(6,645)(7,603)
Interest paid, net of amounts capitalized of $8.0 million in 2020, $1.8 million in 2019 and $0.2 million in 2018
191,561 179,722 158,071 
Non-cash investing activities:
Asset retirement costs capitalized $14,736 33,874 346,387 
(Increase) decrease in capital expenditure accrual84,645 (73,426)9,817 
1 Excludes receivable/payable balances relating to mark-to-market of crude contracts.
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Note P – Accumulated Other Comprehensive Loss
The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2020 and December 31, 2019 and the changes during 2020 and 2019 are presented net of taxes in the following table.
(Thousands of dollars)
Foreign
Currency
Translation
Gains (Losses)		Retirement and
Postretirement
Benefit Plan
Adjustments
 
Deferred
Loss on
Interest
Rate
Derivative
Hedges
 
Total
Balance at December 31, 2018(419,852)(182,036)(7,899)(609,787)
2018 components of other comprehensive income (loss):
Before reclassifications to income66,600 (47,264)— 19,336 
Reclassifications to income— 11,285 ¹5,005 16,290 
Net other comprehensive income66,600 (35,979)5,005 35,626 
Balance at December 31, 2019(353,252)(218,015)(2,894)(574,161)
2019 components of other comprehensive income (loss):
Before reclassifications to income29,241 (70,815)— (41,574)
Reclassifications to income— 13,198 ¹1,204 ²14,402 
Net other comprehensive income (loss)29,241 (57,617)1,204 (27,172)
Balance at December 31, 2020$(324,011)(275,632)(1,690)(601,333)
1 Reclassifications before taxes of $17,694 and $14,380 are included in the computation of net periodic benefit expense in 2020 and 2019, respectively.  See Note L for additional information.  Related income taxes of $4,496 and $3,095 are included in income tax expense in 2020 and 2019, respectively.
2 Reclassifications before taxes of $1,525 and $6,335 are included in Interest expense in 2020 and 2019, respectively.  Related income taxes of $321 and $1,330 are included in income tax expense in 2020 and 2019, respectively. See Note M for additional information.
Note Q – Assets and Liabilities Measured at Fair Value
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet.  The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality.  Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The fair value measurements for these assets and liabilities at December 31, 2020 and 2019 are presented in the following table
December 31, 2020December 31, 2019
(Thousands of dollars)
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets:
Commodity derivative contracts$— 13,050 — 13,050 — — — — 
$— 13,050 — 13,050 — — — — 
Liabilities:
Nonqualified employee savings plans$14,988 — — 14,988 17,035 — — 17,035 
Commodity derivative contracts— 102,675 — 102,675 — 33,364 — 33,364 
Contingent consideration— — 133,004 133,004 — — 146,787 146,787 
$14,988 102,675 133,004 250,667 17,035 33,364 146,787 197,186 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note Q – Assets and Liabilities Measured at Fair Value (Contd.)

The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.
The fair value of West Texas Intermediate (WTI) crude oil contracts in 2020 and 2019 was based on active market quotes for WTI crude oil. The income effect of changes in fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income (loss). 
The Company’s contingent consideration liabilities (with PAI and LLOG, as further described in Note G) are measured at fair value on a recurring basis and are categorized as Level 3 in the fair value hierarchy.  The contingent consideration liabilities are valued using a Monte Carlo simulation model, which used the following assumptions as of December 31, 2020: (i) the remaining expected life of 2 years for LLOG and 5 years for PAI, (ii) West Texas Intermediate forward strip pricing with historical volatility of 9.9%, and (iii) a risk-free interest rate of 0.68%. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations.
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at December 31, 2020 and 2019.
The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2020 and 2019.  The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties.  The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts.  The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities.  The Company has off-balance sheet exposures relating to certain letters of credit.  The fair value of these, which represents fees associated with obtaining the instruments, was nominal.
December 31,
20202019
(Thousands of dollars)
Carrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
Financial assets (liabilities):    
Current and long-term debt$(2,988,067)(2,948,171)(2,803,381)(3,074,929)
Fair Values – Nonrecurring
In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers and - see Risk Factors) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $1,206.3 million to reduce the carrying values to their estimated fair values at select properties.
The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.
The fair value information associated with these impaired properties is presented in the following table
Years Ended December 31, 2020
Net Book
Value
Prior to
Impairment		Total
Pretax
Impairment
Fair Value
(Thousands of dollars)
Level 1Level 2Level 3
Assets:
Impaired proved properties
U.S. Offshore$— — 2,618,001 3,770,516 1,152,515 
Other Foreign— — 42,980 82,689 39,709 
Corporate— — 58,199 72,259 14,060 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note R – Commitments
The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada.  The U.S. Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2045, while the Western Canada processing contracts call for minimum monthly payments through 2051.  In the U.S. and Western Canada, future required minimum monthly payments for the next five years are $149.5 million in 2021, $131.2 million in 2022, $112.0 million in 2023, $99.7 million in 2024 and $76.0 million in 2025.  Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement.  Total costs incurred under these service arrangements were $107.6 million in 2020, $117.7 million in 2019, and $52.2 million in 2018.
Commitments for capital expenditures were approximately $747.0 million at December 31, 2020, including $711.5 million for costs to develop deepwater U.S. Gulf of Mexico fields including fields acquired as part of the MP GOM and LLOG transactions and $31.5 million for work at Eagle Ford Shale.
Note S – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to:  tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others.  Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments.  It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment.  Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to recent SEC amendments to this item, the Company will be using a threshold of $1 million for such proceedings.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled.  Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal.  In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control.  Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses.  The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011.  The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites.  However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note S – Environmental and Other Contingencies (Contd.)

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note T – Common Stock Issued and Outstanding
Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2020 is shown below.
(Number of shares outstanding)
202020192018
Beginning of year152,935,361 173,058,829 172,572,873 
Stock options exercised  1
11,359 12,345 21,200 
Restricted stock awards  1
651,905 561,729 464,756 
Treasury shares purchased— (20,697,542)— 
End of year153,598,625 152,935,361 173,058,829 
1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note K due to withholdings for statutory income taxes owed upon issuance of shares.
Note U – Business Segments
Murphy’s reportable segments are organized into geographic areas of operations.  The Company’s exploration and production activity is subdivided into segments for the United States, Canada and all other countries.  Each of these segments derives revenues primarily from the sale of crude oil, condensate, natural gas liquids and/or natural gas.  The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense. 
The Company has several customers that purchase a significant portion of its oil and natural gas production.  During 2020 sales to Chevron represented approximately 24% of the Company’s total sales revenue, and Phillips 66 and affiliated companies represented approximately 18%. In 2019 sales to Chevron represented approximately 25% and Phillips 66 and affiliated companies accounted for 17% of the Company’s total sales revenue. In 2018 sales to Phillips 66 and affiliated companies represented approximately 12% of the Company’s total sales revenue.  Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.
Assets held for sale as of December 31, 2020 include the King’s Quay FPS, the Brunei exploration and production operations, and the Company’s office building in El Dorado, Arkansas. As of December 31, 2019 assets held for sale include the assets and liabilities of the Brunei exploration and production properties and the U.K. refining and marketing operations. The U.K. and Malaysian operations have been reported as Discontinued operations for all periods presented in these consolidated financial statements. The Company completed the sale of its Malaysian assets in 2019.  
Information about business segments and geographic operations is reported in the following tables.  For geographic purposes, revenues are attributed to the country in which the sale occurs.  Corporate and other activities, including interest income, other gains and losses (including foreign exchange gains/losses, and realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals.  As used in the table on the following page, certain long-lived assets at December 31, exclude investments, noncurrent receivables, deferred tax assets, and other intangible assets.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note U - Business Segments (Contd.)
Exploration and Production
(Millions of dollars)
United
States 1
CanadaOtherTotal
E&P		Corporate
and
Other		Discontinued
Operations		Consolidated
Total
Year ended December 31, 2020
Segment income (loss) - including NCI 1
$(1,014.3)(35.0)(85.6)(1,134.9)$(120.3)(7.2)(1,262.4)
Revenues from external customers1,411.8 345.8 1.8 1,759.4 207.9 — 1,967.3 
Interest and other income (loss)(9.9)0.8 0.8 (8.2)(9.1)— (17.3)
Interest expense, net of capitalization— (0.5)(0.4)(0.9)(168.5)— (169.4)
Income tax expense (benefit)(244.2)(21.4)2.1 (263.5)(30.2)— (293.7)
Significant noncash charges (credits)
Impairment of assets1,152.5 — 39.7 1,192.2 14.1 — 1,206.3 
Depreciation, depletion and amortization
749.4 213.2 2.3 964.9 22.3 — 987.2 
Accretion of asset retirement obligations
36.6 5.5 — 42.1 — — 42.1 
Amortization of undeveloped leases
17.2 0.4 9.1 26.7 — — 26.7 
Deferred and noncurrent income taxes
(244.2)(10.6)1.9 (252.9)(25.1)— (278.0)
Additions to property, plant, equipment623.1 118.3 15.2 756.6 — — 756.6 
Total assets at year-end6,915.5 2,404.1 267.7 9,587.3 1,032.9 0.7 10,620.9 
Year ended December 31, 2019
Segment income (loss) - including NCI 1
$518.4 (4.3)(53.5)460.6 $(271.8)1,064.5 1,253.3 
Revenues from external customers2,367.0 447.0 11.6 2,825.6 3.5 — 2,829.1 
Interest and other income (loss)(13.4)(1.5)(0.9)(15.8)(6.7)— (22.5)
Interest expense, net of capitalization— (0.1)(0.4)(0.5)(218.8)— (219.3)
Income tax expense (benefit)115.6 (2.9)(12.4)100.3 (85.6)— 14.7 
Significant noncash charges (credits)
Depreciation, depletion and amortization
878.7 243.0 3.5 1,125.2 22.6 — 1,147.8 
Accretion of asset retirement obligations
34.4 6.1 — 40.5 — — 40.5 
Amortization of undeveloped leases
23.1 1.3 3.6 28.0 — — 28.0 
Deferred and noncurrent income taxes
111.8 14.0 (13.4)112.4 (83.9)— 28.5 
Additions to property, plant, equipment2,193.3 284.1 69.8 2,547.2 13.6 — 2,560.8 
Total assets at year-end8,043.3 2,303.7 308.6 10,655.6 1,046.2 16.7 11,718.5 
Year ended December 31, 2018
Segment income (loss) - including NCI 1
$242.9 51.1 (16.6)277.4 $(108.2)250.3 419.5 
Revenues from external customers1,332.7 470.5 22.2 1,825.4 (34.0)— 1,791.4 
Interest and other income (loss)— — — — 7.8 — 7.8 
Interest expense, net of capitalization— — 0.2 0.2 (180.6)— (180.4)
Income tax expense (benefit)68.1 14.5 (25.3)57.3 (183.4)— (126.1)
Significant noncash charges (credits)
Depreciation, depletion and amortization
519.5 232.4 3.5 755.4 20.2 — 775.6 
Accretion of asset retirement obligations
19.5 7.6 — 27.1 — — 27.1 
Amortization of undeveloped leases
36.8 0.8 2.5 40.1 — — 40.1 
Deferred and noncurrent income taxes
68.1 16.5 (25.7)58.9 (242.1)— (183.2)
Additions to property, plant, equipment1,343.5 373.8 15.9 1,733.2 22.7 138.6 1,894.5 
Total assets at year-end6,342.9 1,711.9 188.1 8,242.9 1,118.5 1,691.2 11,052.6 
1 Includes results attributable to a noncontrolling interest in MP GOM.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
Note U - Business Segments (Contd.)
Geographic InformationCertain Long-Lived Assets at December 31
(Millions of dollars)
United
States		CanadaOtherTotal
2020$6,395.7 1,702.5 170.8 8,269.0 
20198,003.9 1,761.2 204.6 9,969.7 
20186,634.3 1,644.6 153.2 8,432.1 

Note V – Leases
Nature of Leases
The Company has entered into various operating leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 20 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.
Related Expenses
Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:
Year Ended December 31,
(Thousands of dollars)Financial Statement Category20202019
Operating lease 1,2
Lease operating expenses$208,104 $208,674 
Operating lease 2
Transportation, gathering and processing39,121 41,113 
Operating lease 2
Selling and general expense10,638 12,325 
Operating lease 2
Other operating expense9,524 2,588 
Operating lease 2
Property, plant and equipment40,227 133,837 
Operating lease 2
Asset retirement obligations— 3,024 
Operating leaseImpairment of assets6,565 — 
Operating lease 2
Exploration Expenses994 — 
Finance lease
Amortization of assetDepreciation, depletion and amortization— 420 
Interest on lease liabilitiesInterest expense, net372 202 
Sublease incomeOther income(1,118)(1,419)
Net lease expense$314,427 $400,764 
1  For the year ended December 31, 2020 and 2019, includes variable lease expenses of $21.8 million and $28.7 million, primarily related to additional volumes processed at a natural gas processing plant.
2  For the year ended December 31, 2020, includes $73.9 million in Lease operating expense, $22.9 million for Transportation, gathering and processing, $3.3 million in Selling and general expense, $2.5 million in Other operating expense, $25 million in Property, plant and equipment, net relating to short-term leases due within 12 months..  For the year ended December 31, 2019, includes $56.3 million in Lease operating expense, $4.3 million in Selling general expense, $2.6 million in Other operating expense, $102.7 million in Property, plant and equipment, net and $3 million in Asset retirement obligations relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued
Note V – Leases (Contd.)

Maturity of Lease Liabilities
(Thousands of dollars)
Operating Leases 1
Finance LeasesTotal
2021$149,099 1,068 150,167 
2022140,029 1,068 141,097 
2023136,909 1,069 137,978 
2024131,894 1,069 132,963 
202581,647 1,069 82,716 
Remaining708,931 3,473 712,404 
Total future minimum lease payments1,348,509 8,816 1,357,325 
Less imputed interest(399,663)(1,566)(401,229)
Present value of lease liabilities 2
$948,846 7,250 956,096 
1 Excludes $90 million of minimum lease payments for leases entered but not yet commenced. These payments relate to an offshore drilling rig and payments are planned to commence in the second quarter of 2021 for 16 months.
2 Includes both the current and long-term portion of the lease liabilities. Financing lease pertains to Brunei, which is classified as held for sale on the Consolidated Balance Sheet as of December 31, 2020.
Lease Term and Discount Rate
December 31, 2020
Weighted average remaining lease term:
Operating leases8 years
Finance leases11 years
Weighted average discount rate:
Operating leases5.7 %
Finance leases5.1 %
Other Information
Year Ended December 31,
(Thousands of dollars)20202019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$160,385 $193,968 
Operating cash flows from finance leases372 408 
Financing cash flows from finance leases695 688 
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases ¹$453,719 $125,026 
1 For the year ended December 31, 2020, includes $268.8 million related to a 5-year lease for the Cascade/Chinook FPSO in the U.S. Gulf of Mexico and $168.4 million related to a 20-year lease for a gas plant expansion in Canada.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note W – Restructuring Charges
On May 6, 2020, the Company announced that it was closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net loss during the year ended December 31, 2020 . These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado is classified as held for sale as of December 31, 2020. Restructuring charges are primarily reported in the Corporate segment.

The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the year ended December 31, 2020:
(Thousands of dollars)Year Ended December 31, 2020
Severance$25,088 
Contract exit costs and other13,993 
Pension and termination benefit charges10,913 
Restructuring charges$49,994 

The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at December 31, 2020, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet:
(Thousands of dollars)
Restructuring accruals$32,430 
Utilizations(25,500)
Liability at December 31, 2020$6,930 
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SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED)
The following unaudited schedules are presented in accordance with required disclosures about Oil and Natural gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies.  Additional background information concerning some of the schedules follows:
SCHEDULE 1 – SUMMARY OF TOTAL PROVED EQUIVALENT RESERVES
SCHEDULE 2 – SUMMARY OF PROVED CRUDE OIL RESERVES
SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES
SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES
Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year.  Many assumptions and judgmental decisions are required to estimate reserves.  Reserve estimates and future cash flows are based on the average market prices for sales of oil and natural gas on the first calendar day of each month during the year. The average prices used for 2020 were $39.57 per barrel for NYMEX crude oil (WTI), and $1.98 per Mcf for natural gas (Henry Hub). The average prices used for 2019 were $55.69 per barrel for NYMEX crude oil (WTI), and $2.57 per Mcf for natural gas (Henry Hub). The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub).  Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.
Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data and commercially available technologies to establish “reasonable certainty” of economic producibility.  As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered.  In estimating proved reserves, Murphy uses common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-based studies.  Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves.  Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.  This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates.  The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques.  Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs.  Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.
Production quantities shown are net volumes withdrawn from reservoirs.  These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of natural gas liquids.
All crude oil, natural gas liquid reserves and natural gas reserves are from consolidated subsidiaries (including noncontrolling interest) and proportionately consolidated joint ventures.  The Company has no proved reserves attributable to investees accounted for by the equity method.
SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVES
GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.  
The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production.  Other logical assumptions would likely have resulted in significantly different amounts.
Schedule 7 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2020.
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SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 1 – Summary of Total Proved Equivalent Reserves Based on Average Prices for 2017 – 2020

Equivalents
(Millions of barrels of oil equivalent)
TotalUnited
States		CanadaMalaysia and Other
Proved developed and undeveloped reserves:
December 31, 2017698.2 304.9 259.2 134.1 
Revisions of previous estimates(21.8)(14.0)(18.1)10.4 
Improved recovery0.9 — — 0.9 
Extensions and discoveries122.6 60.1 61.8 0.8 
Purchases of properties106.9 98.7 6.9 1.3 
Production(62.8)(24.0)(21.1)(17.7)
December 31, 2018844.0 425.6 288.6 129.7 
Revisions of previous estimates28.4 (17.9)46.1 0.3 
Extensions and discoveries73.3 62.2 11.1 — 
Purchases of properties76.2 76.2 — — 
Sales of properties(121.5)(0.1)— (121.4)
Production(75.4)(45.9)(21.7)(7.8)
December 31, 2019825.0 500.1 324.1 0.8 
Revisions of previous estimates(194.7)(146.6)(47.3)(0.8)
Extensions and discoveries150.3 19.5 130.7 — 
Sales of properties(1.7)(1.7)— — 
Production(63.9)(42.8)(21.1)— 
December 31, 2020 ¹714.9 328.5 386.4 — 
Proved developed reserves:
December 31, 2017346.7 170.9 114.1 61.7 
December 31, 2018430.2 247.0 124.2 59.1 
December 31, 2019472.3 273.4 198.1 0.8 
December 31, 2020 ²410.8 230.3 180.5 — 
Proved undeveloped reserves:
December 31, 2017351.5 134.0 145.1 72.4 
December 31, 2018413.8 178.7 164.5 70.7 
December 31, 2019352.7 226.7 126.0 — 
December 31, 2020 ³304.1 98.2 205.9 — 
1 Includes proved reserves of 17.4 MMBOE, consisting of 15.6 MMBBL oil, 0.7 MMBBL NGLs, and 6.5 BCF natural gas attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 14.2 MMBOE, consisting of 12.7 MMBBL oil, 0.6 MMBBL NGLs, and 5.7 BCF natural gas attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 3.2 MMBOE, consisting of 2.9 MMBBL oil, 0.1 MMBBL NGLs, and 0.8 BCF natural gas attributable to the noncontrolling interest in MP GOM.








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SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 1 – Summary of Total Proved Equivalent Reserves Based on Average Prices for 2017 – 2020 – Continued

2020 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The negative reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative equivalents revision in the U.S. was primarily attributable to lower capital allocation in the Eagle Ford Shale, and the negative revision in Canada was primarily attributable to the Kaybob Duvernay. Lower commodity prices also resulted in negative equivalents revisions in the U.S offshore and Canada offshore.
Extensions and discoveries - In 2020, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale. Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
2019 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates -  The positive Canadian equivalents reserves revisions in 2019 resulted from improved performance in the Tupper Montney asset which offset reserves reductions from deferrals of capital expenditures at Kaybob Duvernay. The 2019 negative equivalents revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily the Tilden area.
Extensions and discoveries - In 2019, proved equivalent reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay.  Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.
Purchases and sales of properties - In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG.  In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico and partial ownership in the Jagus East field in Brunei (which is now held for sale). The Company’s Malaysia assets were divested in 2019.
2018 Comments for Proved Equivalent Reserves Changes
Revisions of previous estimates - The 2018 negative proved equivalents revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window.  The negative Canadian equivalent reserves revisions in 2018 resulted from deferrals of capital expenditures of the Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans.  The positive revisions for proved equivalent reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field.
Improved recovery - The 2018 Malaysia proved equivalent reserve addition was due to favorable impacts from gas lift activity at the Kikeh field.
Extensions and discoveries - In 2018, proved equivalent reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.  Proved equivalent reserves were also added for drilling activities in the U.S. offshore.
Purchases of properties - In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations.  In addition, the Company acquired partial ownership in the Jagus East field in Brunei.




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SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2017 – 2020

(Millions of barrels)
TotalUnited
States		CanadaMalaysia and Other
Proved developed and undeveloped crude oil reserves:
December 31, 2017328.1 224.7 51.5 51.9 
Revisions of previous estimates(15.3)(15.0)(8.0)7.7 
Improved recovery0.8 — — 0.8 
Extensions and discoveries58.9 42.9 16.0 — 
Purchases of properties93.6 92.3 — 1.3 
Production(33.6)(18.4)(4.5)(10.7)
December 31, 2018432.5 326.5 55.0 51.0 
Revisions of previous estimates(31.0)(17.1)(14.0)0.1 
Extensions and discoveries58.2 49.2 9.0 — 
Purchases of properties56.3 56.3 — — 
Production(46.3)(37.0)(4.7)(4.6)
December 31, 2019423.9 377.8 45.3 0.8 
Revisions of previous estimates(137.4)(116.8)(19.8)(0.8)
Extensions and discoveries19.6 14.5 5.1 — 
Sales of properties(1.5)(1.5)— — 
Production(38.1)(33.4)(4.7)— 
December 31, 2020 ¹266.5 240.6 25.9 — 
Proved developed crude oil reserves:
December 31, 2017185.5 126.3 21.9 37.3 
December 31, 2018249.3 189.0 23.3 37.0 
December 31, 2019230.9 205.0 25.1 0.8 
December 31, 2020 ²179.8 161.4 18.4 — 
Proved undeveloped crude oil reserves:
December 31, 2017142.6 98.4 29.6 14.6 
December 31, 2018183.2 137.5 31.7 14.0 
December 31, 2019193.0 172.8 20.2 — 
December 31, 2020 ³86.7 79.2 7.5 — 
1 Includes total proved reserves of 15.6 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 12.7 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 2.9 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.







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SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2017 – 2020 – Continued

2020 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates - The negative crude oil reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative oil revision in the U.S. was primarily attributable to lower capital allocation in the Eagle Ford Shale, and the negative revision in Canada was primarily attributable to the Kaybob Duvernay. Lower commodity prices also resulted in negative oil reserves revisions in the U.S offshore and Canada offshore.
Extensions and discoveries - In 2020, proved oil reserves were added for drilling activities predominantly in the U.S. offshore and the Eagle Ford Shale. Proved oil reserves were also added for drilling activities in Canada offshore.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
2019 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates – The 2019 negative crude oil revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily in the Tilden area. The negative Canadian oil reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay.
Extensions and discoveries – In 2019, proved oil reserves were added in the U.S. for drilling activities both in the Eagle Ford Shale and in Canada at Kaybob Duvernay.  Proved oil reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.
Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019.
2018 Comments for Proved Crude Oil Reserves Changes
Revisions of previous estimates – The 2018 negative crude oil revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window.  The negative Canadian oil reserves revisions in 2018 resulted from deferrals of capital expenditures at Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans.  The positive revisions for crude oil reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field.
Improved recovery – The 2018 Malaysia crude oil proved reserve addition was due to favorable impacts from natural gas lift activity at the Kikeh field.
Extensions and discoveries – In 2018, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.  Proved oil reserves were also added for drilling activities in the U.S. offshore.
Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations.  In addition, the Company acquired partial ownership in the Jagus East field in Brunei.

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SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 3 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 2017 – 2020

(Millions of barrels)
TotalUnited
States		CanadaMalaysia and Other
Proved developed and undeveloped NGL reserves:
December 31, 201748.9 43.0 5.6 0.3 
Revisions of previous estimates(6.2)(5.3)(1.6)0.7 
Extensions and discoveries12.0 9.7 2.3 — 
Purchase of properties3.0 3.0 — — 
Production(3.5)(2.8)(0.4)(0.3)
December 31, 201854.2 47.6 5.9 0.7 
Revisions of previous estimates(5.0)(2.5)(2.5)— 
Extensions and discoveries6.8 6.4 0.4 — 
Purchases of properties5.2 5.2 — — 
Production(4.5)(3.9)(0.5)(0.1)
December 31, 201956.1 52.8 3.3 — 
Revisions of previous estimates(16.4)(17.1)0.7 — 
Extensions and discoveries2.8 2.7 0.1 — 
Sales of properties(0.1)(0.1)— — 
Production(4.2)(3.7)(0.5)— 
December 31, 2020 ¹38.2 34.6 3.6 — 
Proved developed NGL reserves:
December 31, 201724.6 23.3 1.0 0.3 
December 31, 201827.3 24.9 1.7 0.7 
December 31, 201928.1 26.2 1.9 — 
December 31, 2020 ²28.7 25.5 3.2 — 
Proved undeveloped NGL reserves:
December 31, 201724.3 19.7 4.6 — 
December 31, 201826.9 22.7 4.2 — 
December 31, 201928.0 26.6 1.4 — 
December 31, 2020 ³9.5 9.1 0.4 — 
1 Includes total proved reserves of 0.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 0.6 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 0.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.









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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 3 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 2017 – 2020 – Continued

2020 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates - The negative NGL reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative NGL revision in the U.S. was primarily attributable to lower capital allowance in the Eagle Ford Shale. The positive revision in Canada was primarily attributable to higher yields at the Kaybob Duvernay due to improved plant recoveries.
Extensions and discoveries - In 2020, proved NGL reserves were added for drilling activities predominantly in the U.S. at the Eagle Ford Shale.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
2019 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates – The negative 2019 NGL proved reserves revision in the U.S. was primarily due to midstream elections in the Eagle Ford Shale resulting in lower NGL yields. The negative Canadian NGL reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay.  
Extensions and discoveries – In 2019, proved NGL reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay area in onshore Canada. Proved NGL reserves were also added for drilling activities in the U.S. offshore.
Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019.
2018 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates – The negative 2018 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on removal of proved undeveloped locations outside the 5-year development window.  The negative Canadian NGL reserves revisions in 2018 resulted from deferrals of capital expenditures at Kaybob Duvernay.  The positive revisions for NGL reserves in Malaysia were principally attributable to improved performance for natural gas fields offshore Sarawak.
Extensions and discoveries – In 2018, proved NGL reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.
Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations.

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2017 – 2020

(Billions of cubic feet)
TotalUnited
States		CanadaMalaysia and Other
Proved developed and undeveloped natural gas reserves:
    
December 31, 20171,927.1 223.3 1,212.4 491.4 
Revisions of previous estimates(1.8)37.6 (51.2)11.8 
Extensions and discoveries310.3 44.7 261.0 4.6 
Purchases of properties61.7 20.3 41.4 — 
Production(154.3)(16.9)(97.2)(40.2)
December 31, 20182,143.6 309.0 1,366.4 468.2 
Revisions of previous estimates386.5 10.3 375.3 0.9 
Extensions and discoveries49.8 39.5 10.3 — 
Purchases of properties88.3 88.3 — — 
Production(147.8)(30.2)(99.1)(18.5)
December 31, 20192,069.7 416.8 1,652.9 — 
Revisions of previous estimates(245.4)(76.2)(169.2)— 
Extensions and discoveries767.2 14.0 753.2 — 
Sales of properties(0.7)(0.7)— — 
Production(129.8)(34.4)(95.4)— 
December 31, 2020 1,4
2,461.0 319.5 2,141.5 — 
Proved developed natural gas reserves:
December 31, 2017819.3 127.7 547.0 144.6 
December 31, 2018921.6 198.3 595.0 128.3 
December 31, 20191,279.8 253.1 1,026.7 — 
December 31, 2020 ²1,213.8 260.2 953.6 — 
Proved undeveloped natural gas reserves:
December 31, 20171,107.8 95.6 665.5 346.7 
December 31, 20181,222.0 110.7 771.4 339.9 
December 31, 2019789.9 163.7 626.2 — 
December 31, 2020 ³1,247.2 59.3 1,187.9 — 
1 Includes total proved reserves of 6.5 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
2 Includes proved developed reserves of 5.7 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
3 Includes proved undeveloped reserves of 0.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
4 Includes proved natural gas reserves to be consumed in operations as fuel of 72.0 BCF and 108.8 BCF for the U.S. and Canada, respectively, with 1.6 BCF attributable to the noncontrolling interest in MP GOM.









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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED)
Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2016 – 2019
2020 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates - The negative natural gas reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative natural gas revision in the U.S. was primarily attributable to lower capital allocation in the Eagle Ford Shale which offset positive natural gas revisions in the Gulf of Mexico. The negative revision in Canada was primarily attributable to the Kaybob Duvernay.
Extensions and discoveries - In 2020, proved natural gas reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale.
Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico.
2019 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates –  In 2019, the positive natural gas revisions in Canada resulted from improved performance in the Tupper Montney asset and adjustments relating to royalties. The positive revision for natural gas reserves in the Eagle Ford Shale was primarily attributable to producing well performance.
Extensions and discoveries – In 2019, proved natural gas reserves were added in the U.S. for development drilling activities in both the Eagle Ford Shale and in Canada at Tupper Montney and Kaybob Duvernay.  Proved natural gas reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.
Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019.
2018 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates –  In 2018, the U.S. positive natural gas revision was primarily due to drilling within the Eagle Ford Shale.  The 2018 negative natural gas revisions in Canada resulted from deferrals of capital expenditures at Kaybob Duvernay partially offset by positive performance revisions in the Tupper Montney asset.  The positive revision for natural gas reserves in Malaysia was primarily attributable to positive performance revisions at the Company’s Sarawak projects offset somewhat by negative Block H revisions attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher natural gas prices.
Improved recovery – The 2018 Malaysia natural gas proved reserve addition was due to favorable impacts from natural gas lift activity at the Kikeh field.
Extensions and discoveries – In 2018, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale.  Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper Montney and Kaybob Duvernay areas in onshore Canada.  In Malaysia, proved natural gas reserves were added in the Merapuh field in Sarawak from field development activities.
Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations.  In addition, the Company acquired acreage in Tupper Montney in onshore Canada.

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 5 – Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

(Millions of dollars)
United
States		CanadaMalaysiaOtherTotal
Year ended December 31, 2020
Property acquisition costs
Unproved$6.5 0.5 — 7.3 14.3 
Proved0.2 — — — 0.2 
Total acquisition costs6.7 0.5 — 7.3 14.5 
Exploration costs 1
34.3 (0.4)— 24.7 58.6 
Development costs 1
609.2 120.8 — 6.8 736.8 
Total costs incurred650.2 120.9 — 38.8 809.9 
Charged to expense
Geophysical and other costs14.3 0.7 — 23.6 38.6 
Total charged to expense14.3 0.7 — 23.6 38.6 
Property additions$635.9 120.2 — 15.2 771.3 
Year ended December 31, 2019
Property acquisition costs
Unproved$533.8 0.2 — 13.0 547.0 
Proved733.1 — — — 733.1 
Total acquisition costs1,266.9 0.2 — 13.0 1,280.1 
Exploration costs 1
44.8 6.4 — 67.4 118.6 
Development costs 1
979.0 281.8 — 21.6 1,282.4 
Total costs incurred2,290.7 288.4 — 102.0 2,681.1 
Charged to expense
Geophysical and other costs21.6 0.5 — 32.2 54.3 
Total charged to expense21.6 0.5 — 32.2 54.3 
Property additions$2,269.1 287.9 — 69.8 2,626.8 
Year ended December 31, 2018
Property acquisition costs
Unproved$2.8 — — 0.2 3.0 
Proved794.3 — — — 794.3 
Total acquisition costs797.1 — — 0.2 797.3 
Exploration costs 1
88.1 0.6 2.2 35.1 126.0 
Development costs 1
853.7 373.8 145.9 16.6 1,390.0 
Total costs incurred1,738.9 374.4 148.1 51.9 2,313.3 
Charged to expense
Dry hole expense16.0 — 0.1 4.5 20.6 
Geophysical and other costs13.4 0.6 2.1 31.3 47.4 
Total charged to expense29.4 0.6 2.2 35.8 68.0 
Property additions$1,709.5 373.8 145.9 16.1 2,245.3 






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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 5 – Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

1 Includes noncash asset retirement costs as follows:
2020
Exploration costs$— — — — — 
Development costs12.8 1.9 — — 14.7 
$12.8 1.9 — — 14.7 
2019
Exploration costs$— — — — — 
Development costs75.8 3.8 — — 79.6 
$75.8 3.8 — — 79.6 
2018
Exploration costs$— — — — — 
Development costs366.0 — 7.3 0.2 373.5 
$366.0 — 7.3 0.2 373.5 
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities 1
(Millions of dollars)
United
States		CanadaOtherTotal
Year ended December 31, 2020    
Revenues    
Crude oil and natural gas liquids sales$1,335.8 174.0 1.8 1,511.6 
Natural gas sales69.4 170.6 — 240.1 
Total oil and natural gas revenues1,405.3 344.6 1.8 1,751.7 
Other operating revenues6.5 1.2 — 7.7 
Total revenues1,411.8 345.8 1.8 1,759.4 
Costs and expenses
Lease operating expenses476.9 121.6 1.6 600.1 
Severance and ad valorem taxes27.2 1.3 — 28.5 
Transportation, gathering and processing127.7 44.7 — 172.4 
Restructuring expenses1.2 — — 1.2 
Exploration costs charged to expense35.5 0.6 23.6 59.7 
Undeveloped lease amortization17.2 0.4 9.2 26.8 
Depreciation, depletion and amortization749.4 213.2 2.3 964.9 
Accretion of asset retirement obligations36.6 5.6 — 42.2 
Impairment of assets1,152.5 — 39.7 1,192.2 
Selling and general expenses24.6 17.1 7.1 48.8 
Other expenses (benefits)21.5 (2.3)1.8 21.0 
Total costs and expenses2,670.3 402.2 85.3 3,157.8 
Results of operations before taxes(1,258.5)(56.4)(83.5)(1,398.4)
Income tax expense (benefit)(244.2)(21.4)2.1 (263.5)
Results of operations$(1,014.3)(35.0)(85.6)(1,134.9)
Year ended December 31, 2019
Revenues
Crude oil and natural gas liquids sales$2,285.8 287.4 11.6 2,584.8 
Natural gas sales73.9 158.4 — 232.3 
Total oil and natural gas revenues2,359.7 445.8 11.6 2,817.1 
Other operating revenues7.3 1.2 — 8.5 
Total revenues2,367.0 447.0 11.6 2,825.6 
Costs and expenses
Lease operating expenses461.5 142.4 1.3 605.2 
Severance and ad valorem taxes46.6 1.4 — 48.0 
Transportation, gathering and processing140.8 35.5 — 176.3 
Exploration costs charged to expense21.4 0.6 45.3 67.3 
Undeveloped lease amortization23.1 1.3 3.6 28.0 
Depreciation, depletion and amortization878.7 243.0 3.5 1,125.2 
Accretion of asset retirement obligations34.4 6.1 — 40.5 
Selling and general expenses74.3 30.0 22.5 126.8 
Other expenses52.2 (6.1)1.3 47.4 
Total costs and expenses1,733.0 454.2 77.5 2,264.7 
Results of operations before taxes634.0 (7.2)(65.9)560.9 
Income tax expense (benefit)115.6 (2.9)(12.4)100.3 
Results of operations$518.4 (4.3)(53.5)460.6 
1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 6 – Results of Operations for Oil and Gas Producing Activities 1 – Continued
(Millions of dollars)
United
States		CanadaOtherTotal
Year ended December 31, 2018
Revenues
Crude oil and natural gas liquids sales$1,277.7 302.8 6.1 1,586.6 
Natural gas sales53.6 166.3 — 219.9 
Total oil and natural gas revenues1,331.3 469.1 6.1 1,806.5 
Other operating revenues1.4 1.4 16.1 18.9 
Total revenues1,332.7 470.5 22.2 1,825.4 
Costs and expenses
Lease operating expenses230.5 122.6 0.7 353.8 
Severance and ad valorem taxes50.9 1.2 — 52.1 
Transportation, gathering and processing43.1 31.9 — 75.0 
Exploration costs charged to expense29.4 0.6 31.6 61.6 
Undeveloped lease amortization36.8 0.8 2.5 40.1 
Depreciation, depletion and amortization519.5 232.4 3.5 755.4 
Accretion of asset retirement obligations19.5 7.7 — 27.2 
Impairment of assets20.0 — — 20.0 
Selling and general expenses49.0 26.8 23.5 99.3 
Other expenses23.0 (19.1)2.3 6.2 
Total costs and expenses1,021.7 404.9 64.1 1,490.7 
Results of operations before taxes311.0 65.6 (41.9)334.7 
Income tax expense (benefit)68.1 14.5 (25.3)57.3 
Results of operations$242.9 51.1 (16.6)277.4 
1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM.
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Natural Gas Reserves 1
(Millions of dollars)
United
States		CanadaMalaysia & Other Total
December 31, 2020    
Future cash inflows$9,976.7 4,617.5 — 14,594.2 
Future development costs(1,289.8)(404.3)— (1,694.1)
Future production costs(5,777.5)(2,634.6)— (8,412.1)
Future income taxes— (166.8)— (166.8)
Future net cash flows2,909.4 1,411.8 — 4,321.2 
10% annual discount for estimated timing of cash flows
(1,079.2)(623.4)— (1,702.6)
Standardized measure of discounted future net cash flows$1,830.2 788.4 — 2,618.6 
December 31, 2019
Future cash inflows$23,565.6 4,912.1 55.7 28,533.4 
Future development costs(4,137.8)(723.7)(0.3)(4,861.8)
Future production costs(8,986.2)(2,549.9)(29.9)(11,566.0)
Future income taxes(1,709.3)(414.5)(14.1)(2,137.9)
Future net cash flows8,732.3 1,224.0 11.4 9,967.7 
10% annual discount for estimated timing of cash flows(3,633.1)(504.0)(3.0)(4,140.1)
Standardized measure of discounted future net cash flows$5,099.2 720.0 8.4 5,827.6 
December 31, 2018
Future cash inflows$23,473.9 5,437.5 5,511.6 34,423.0 
Future development costs(3,279.1)(1,362.7)(517.4)(5,159.2)
Future production costs(7,279.5)(2,693.0)(2,813.4)(12,785.9)
Future income taxes(2,216.5)(236.4)(472.0)(2,924.9)
Future net cash flows10,698.8 1,145.4 1,708.8 13,553.0 
10% annual discount for estimated timing of cash flows(4,295.4)(531.4)(446.3)(5,273.1)
Standardized measure of discounted future net cash flows
$6,403.4 614.0 1,262.5 8,279.9 
1 Includes noncontrolling interest in MP GOM.




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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Natural Gas Reserves – Continued 1
Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.
(Millions of dollars)
202020192018
Net changes in prices and production costs 2
$(5,942.1)(2,993.9)2,972.6 
Net changes in development costs2,215.1 (675.7)(1,891.1)
Sales and transfers of oil and natural gas produced, net of production costs(1,123.1)(2,163.8)(1,978.6)
Net change due to extensions and discoveries568.5 1,221.9 1,930.3 
Net change due to purchases and sales of proved reserves(14.6)(628.1)3,152.4 
Development costs incurred 
736.8 1,282.4 1,017.3 
Accretion of discount699.3 1,002.0 469.5 
Revisions of previous quantity estimates(1,461.3)(71.2)(347.8)
Net change in income taxes1,112.4 574.1 (967.6)
Net increase (decrease)(3,209.0)(2,452.3)4,357.0 
Standardized measure at January 15,827.6 8,279.9 3,922.9 
Standardized measure at December 31$2,618.6 5,827.6 8,279.9 
1 Includes noncontrolling interest in MP GOM.
2 The average prices used for 2020 were $39.57 per barrel for NYMEX crude oil (WTI), and $1.98 per Mcf for natural gas (Henry Hub).The average prices used for 2019 were $55.69 per barrel for NYMEX crude oil (WTI), and $2.57 per Mcf for natural gas (Henry Hub). The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub).
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued
Schedule 8 – Capitalized Costs Relating to Oil and Natural Gas Producing Activities
(Millions of dollars)
United
States		CanadaOtherTotal
December 31, 2020
Unproved oil and natural gas properties$646.0 22.2 137.5 805.7 
Proved oil and natural gas properties14,011.4 4,619.4 23.8 18,654.6 
Gross capitalized costs14,657.4 4,641.6 161.3 19,460.3 
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties(105.0)— (14.5)(119.5)
Proved oil and natural gas properties(8,166.5)(2,944.3)(20.7)(11,131.5)
Net capitalized costs$6,385.9 1,697.3 126.1 8,209.3 
December 31, 2019
Unproved oil and natural gas properties$1,116.6 243.7 210.4 1,570.7 
Proved oil and natural gas properties13,292.6 4,176.7 21.1 17,490.4 
Gross capitalized costs14,409.2 4,420.4 231.5 19,061.1 
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties(136.4)(225.4)(25.9)(387.7)
Proved oil and natural gas properties(6,298.9)(2,438.6)(2.4)(8,739.9)
Net capitalized costs$7,973.9 1,756.4 203.2 9,933.5 
Note:    Unproved oil and natural gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)

(Millions of dollars except per share amounts)
First
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter
Year 1,2
Year ended December 31, 2020     
Revenue from contracts with customers$600.6 285.7 425.3 440.1 1,751.7 
Income (loss) from continuing operations before income taxes(595.4)(417.9)(328.4)(207.3)(1,549.0)
Income (loss) from continuing operations(503.8)(323.1)(265.9)(162.5)(1,255.3)
Net income (loss) including noncontrolling interest(508.7)(324.4)(266.6)(162.7)(1,262.4)
Net income (loss) attributable to Murphy(416.1)(317.2)(243.5)(171.9)(1,148.8)
Income (loss) from continuing operations per Common share
Basic(2.68)(2.05)(1.58)(1.11)(7.43)
Diluted(2.68)(2.05)(1.58)(1.11)(7.43)
Net income (loss) per Common share
Basic(2.71)(2.06)(1.59)(1.11)(7.48)
Diluted(2.71)(2.06)(1.59)(1.11)(7.48)
Cash dividend per Common share0.25 0.125 0.125 0.125 0.625 
Year ended December 31, 2019
Revenue from contracts with customers$629.4 680.4 750.3 757.0 2,817.1 
Income (loss) from continuing operations before income taxes33.7 107.9 177.1 (115.3)203.5 
Income (loss) from continuing operations22.9 98.8 158.3 (91.3)188.8 
Net income including noncontrolling interest72.8 123.2 1,111.7 (54.4)1,253.3 
Net income attributable to Murphy40.2 92.3 1,089.0 (71.7)1,149.7 
Income (loss) from continuing operations per Common share
Basic(0.06)0.40 0.85 (0.71)0.52 
Diluted(0.06)0.40 0.84 (0.70)0.52 
Net income (loss) per Common share
Basic0.23 0.55 6.79 (0.71)7.01 
Diluted0.23 0.54 6.76 (0.47)6.98 
Cash dividend per Common share0.25 0.25 0.25 0.25 1.00 
1 Revenue from contracts with customers, Income (loss) from continuing operations before income taxes, Income (loss) from continuing operations and Net income (loss) including noncontrolling interest include results attributable to the noncontrolling interest in MP GOM.
2 2020 results include impairment charges of $1,206.3 million as a result of declines in future oil and natural gas prices at the time of impairment (principally driven by reduced demand in response to the COVID-19 pandemic - see Risk Factors).
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE II - VALUATION ACCOUNTS AND RESERVES
(Millions of dollars)
Balance at
January 1		Charged
to Expense		Deductions
Other 1
Balance at December 31
2020
Deducted from asset accounts:
Allowance for doubtful accounts$1.6 — — — 1.6 
Deferred tax asset valuation allowance103.1 3.3 — — 106.4 
2019
Deducted from asset accounts:
Allowance for doubtful accounts$1.6 — — — 1.6 
Deferred tax asset valuation allowance166.9 10.9 — (74.7)103.1 
2018
Deducted from asset accounts:
Allowance for doubtful accounts$1.6 — — — 1.6 
Deferred tax asset valuation allowance407.3 3.3 — (243.7)166.9 
1 The amounts in 2019 and 2018 for deferred tax asset valuation allowance are primarily associated with utilization of foreign tax credit carryforwards.
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GLOSSARYABBREVIATIONS
3D seismic
three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons
deepwater
offshore location in greater than 1,000 feet of water
downstream
refining and marketing operations
dry hole
an unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expense
exploratory
wildcat and delineation, e.g., exploratory wells
hydrocarbons
organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products
operator
the company serving as the manager and often the decision-maker of a drilling or production project
production sharing contract
agreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recovered
unitization
combining of multiple mineral or leasehold interests to be able to produce from a common reservoir
upstream
oil and natural gas exploration and production operations, including synthetic oil operation
working interest
right to drill and produce oil and gas on the leased acreage, as well as the obligation to pay costs
ARO - Asset Retirement Obligation
ASU - Accounting Standards Update
BCF - Billion cubic feet
BOED - Barrel of oil equivalent per day
FASB - Financial Accounting Standards Board
FLNG - Floating Liquified Natural Gas
GAAP - U.S. Generally Accepted Accounting Principles
GK - Gumusut/Kakap
MCF - Thousand cubic feet
MMBOE - Million barrels of oil equivalent
MMCF - Million cubic feet
MMCFD – Million cubic feet per day
MOCL - Murphy Oil Company Ltd.
NCI - Noncontrolling interest
NYMEX - New York Mercantile Exchange
OSHA - Occupational Safety and Health Act
PAI – Petrobras Americas Inc., a subsidiary of Petróleo Brasileiro S.A.
QRE - Qualified Reserve Estimators
SEC - U.S. Securities and Exchange Commission
UFA - Unitization Framework Agreement
WTI - West Texas Intermediate