EDGAR 10-K Filing

Company CIK: 717423
Filing Year: 2021
Filename: 717423_10-K_2021_0000717423-21-000014.json

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ITEM 1. BUSINESS
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.
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:
Field Working 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.
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
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.
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 Products Crude
Oil Natural Gas
Liquids Natural Gas 4
Proved Developed Reserves: (MMBOE) (MMBBL) (BCF)
United States 230.3 161.4 25.5 260.2
Onshore
120.0 74.9 18.6 158.8
Offshore 1
110.3 86.5 6.9 101.4
Canada 180.5 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 States 98.2 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
Canada 205.9 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 year 825.0 352.7
Revisions of previous estimates (194.7) (178.0)
Extensions and discoveries 150.3 148.8
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.
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.
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.
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.
Developed Undeveloped Total
Area (Thousands of acres)
Gross Net Gross Net Gross Net
United States - Onshore 109 97 38 35 147 132
- Gulf of Mexico 37 17 539 264 576 281
Total United States 146 114 577 299 723 413
Canada - Onshore 140 107 364 259 504 366
- Offshore 101 8 28 1 129 9
Total Canada 241 115 392 260 633 375
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
Totals 387 229 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 Wells Natural Gas Wells
Gross Net Gross Net
Country
United States - Onshore 1,067 888 - -
- Offshore 58 29 20 10
Total United States 1,125 917 20 10
Canada - Onshore 26 14 366 302
- Offshore 52 4 - -
Total Canada 78 18 366 302
Totals 1,203 935 386 312
Acreage and Well Count (Cont’d.)
Murphy’s net wells drilled in the last three years are shown in the following table.
United States Canada Other Totals
Productive Dry Productive Dry Productive Dry Productive Dry
Exploration - 0.4 0.7 - - - 0.7 0.4
Development 21.5 - 8.9 - - - 30.4 -
Exploration 0.6 - - - - - 0.6 -
Development 84.6 - 18.6 - - - 103.2 -
Exploration 0.5 0.4 - - - - 0.5 0.4
Development 46.6 - 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.
Exploration Development Total
Gross Net Gross Net Gross Net
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,
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.
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 -
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)
Executive and Senior Level Managers 12 %
First- and Mid-Level Managers 17 %
Professionals 34 %
Other (Administrative Support and Field) 7 %
Total 21 %
Minorities 1 Representation (US-Based Only)
Executive and Senior Level Managers 12 %
First- and Mid-Level Managers 23 %
Professionals 33 %
Other (Administrative Support and Field) 31 %
Total 30 %
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.
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
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
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.
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.
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.
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
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.
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.
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.
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
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
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.

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ITEM 2. PROPERTIES
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.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. LEGAL PROCEEDINGS
Discussion of the Company’s legal proceedings are included in Note S - Environmental and Other Contingencies beginning on page 96.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
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.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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 Corporation Devon Energy Corporation Range Resources Corporation
Cabot Oil & Gas Corporation Ovintiv Inc. SM Energy Company
Chesapeake Energy Corporation Hess Corporation Southwestern Energy Company
Cimarex Energy Co. Marathon Oil Corporation Whiting Petroleum Corporation
CNX Resources Corporation Matador Resources Company
2015 2016 2017 2018 2019 2020
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
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
2020 2019 2018 2017 2016
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
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.
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)
2020 2019 2018
(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.
Other key performance metrics (Cont’d.)
Year Ended December 31,
(Millions of dollars, except per barrel of oil equivalents sold)
2020 2019 2018
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, net 169.4 219.3 180.4
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 ¹ 1,072.5 - 20.0
Mark-to-market loss (gain) on crude oil derivative contracts 69.3 33.4 (33.9)
Restructuring expenses 50.0 - -
Accretion of asset retirement obligations 42.1 40.5 27.1
Unutilized rig charges 16.0 - -
Mark-to-market loss (gain) on contingent consideration (13.8) 8.7 (4.8)
Inventory loss 8.3 - -
Discontinued operations (income) loss 7.2 (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.
A summary of Net (loss) income is presented in the following table.
(Millions of dollars)
2020 2019 2018
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)
2020 2019 2018
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 liquids 174.0 287.4 302.8
- 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
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).
Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.
(Dollars per equivalent barrel)
2020 2019 2018
Continuing operations
United States - Eagle Ford Shale
Lease operating expense $ 9.08 8.70 8.84
Severance and ad valorem taxes 2.06 2.82 3.20
Depreciation, depletion and amortization (DD&A) expense 26.22 24.19 24.54
United States - Gulf of Mexico
Lease operating expense 1
11.95 10.89 11.39
DD&A expense 13.48 16.43 16.50
Canada - Onshore
Lease operating expense 4.63 5.49 4.52
Severance and ad valorem taxes 0.07 0.07 0.06
DD&A expense 9.93 10.94 10.61
Canada - Offshore
Lease operating expense 2
17.86 14.95 15.21
DD&A expense 12.01 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 taxes 0.44 0.71 1.16
DD&A expense 15.36 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 taxes 0.47 0.76 1.17
DD&A expense 15.49 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.
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.
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.
The following table contains hydrocarbons produced during the three years ended December 31, 2020.
Barrels per day unless otherwise noted
2020 2019 2018
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.
The following table contains hydrocarbons sold during the three years ended December 31, 2020.
Barrels per day unless otherwise noted
2020 2019 2018
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.
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.
2020 2019 2018
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
Onshore 32.42 50.29 53.85
Offshore 39.40 64.91 70.16
Other
63.51 74.70 71.48
Natural gas liquids - dollars per barrel
United States
Onshore 11.67 14.60 25.68
Gulf of Mexico 1
10.84 15.10 28.27
Canada 2
Onshore 18.54 26.04 37.47
Natural gas - dollars per thousand cubic feet
United States
Onshore 1.95 2.47 3.11
Gulf of Mexico 1
2.04 2.43 3.35
Canada 2
Onshore 1.79 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.
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) 2020 2019 2018
Capital Expenditures
Exploration and production $ 813.3 2,683.2 1,818.8
Corporate 13.3 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) 2020 2019 2018
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 statements 113.0 100.2 -
Acquisition of oil properties per the cash flow statements - 1,212.3 794.6
Geophysical and other exploration expenses 32.3 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
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.
Financial Condition (Contd.)
December 31, 2020 December 31, 2019
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 2,988.1 41.5 % $ 2,803.4 33.9 %
Murphy shareholders' equity 4,214.3 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.
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.
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.
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.
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
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
Total 2021 2022 - 2023 2024 - 2025 After 2025
Debt, excluding interest $ 2,809.7 - 576.4 1,091.1 1,142.2
Operating leases and other leases ¹ 1,357.3 150.2 279.1 215.7 712.4
Capital expenditures, drilling rigs and other ² 1,756.7 746.7 434.5 175.7 399.8
Other long-term liabilities, including debt interest ³ 2,575.4 267.5 375.6 453.5 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.
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:
Commodity Type Volumes
(Bbl/d) Price
(USD/Bbl) Remaining Period
Area Start Date End Date
United States WTI ¹ Fixed price derivative swap 45,000 $42.77 1/1/2021 12/31/2021
United States WTI ¹ Fixed price derivative swap 20,000 $44.88 1/1/2022 12/31/2022
1 West Texas Intermediate
Volumes
(MMcf/d) Price
(CAD/Mcf) Remaining Period
Area Commodity Type Start Date End Date
Montney Natural Gas Fixed price forward sales at AECO 160 C$2.54 1/1/2021 1/31/2021
Montney Natural Gas Fixed price forward sales at AECO 203 C$2.55 2/1/2021 5/31/2021
Montney Natural Gas Fixed price forward sales at AECO 212 C$2.55 6/1/2021 12/31/2021
Montney Natural Gas Fixed price forward sales at AECO 222 C$2.41 1/1/2022 12/31/2022
Montney Natural Gas Fixed price forward sales at AECO 192 C$2.36 1/1/2023 12/31/2023
Montney Natural Gas Fixed price forward sales at AECO 147 C$2.41 1/1/2024 12/31/2024
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
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item appears on pages 55 through 119 of this Form 10-K report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None

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ITEM 9A. CONTROLS AND PROCEDURES
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.

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ITEM 9B. OTHER INFORMATION
Item 9B. OTHER INFORMATION
None
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.

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ITEM 11. EXECUTIVE COMPENSATION
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.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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.”

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.”

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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.”
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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.
Report of Management - Consolidated Financial Statements
Report of Management - Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Note A - Significant Accounting Policies
Note B - New Accounting Principles and Recent Accounting Pronouncements
Note C - Revenue from Contracts with Customers
Note D - Acquisition
Note E - Assets Held for Sale and Discontinued Operations
Note F - Inventories
Note G - Property, Plant, and Equipment
Note H - Financing Arrangements and Debt
Note I - Asset Retirement Obligations
Note J - Income Taxes
Note K - Incentive Plans
Note L - Employee and Retiree Benefit Plans
Note M - Financial Instruments and Risk Management
Note N - Earnings per Share
Note O - Other Financial Information
Note P - Accumulated Other Comprehensive Loss
Note Q - Assets and Liabilities Measured at Fair Value
Note R - Commitments
Note S - Environmental and Other Contingencies
Note T - Common Stock Issued and Outstanding
Note U - Business Segments
Note V - Leases
Note W - Restructuring Charges
Supplemental Oil and Natural Gas Information (unaudited)
Supplemental Quarterly Information (unaudited)
2. Financial Statement Schedules
Schedule II - Valuation Accounts and Reserves
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.
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
2.1 Purchase and sale agreement dated as of April 19, 2019 between LLOG Bluewater Holdings, LLC and LLOG Exploration Offshore, LLC, as seller, and Murphy Exploration & Production Company - USA, as purchaser.
Exhibit 2.1 to Form 8-K filed June 5, 2019
2.2 First Amendment to Purchase and Sale Agreement dated as of May 31, 2019 among Murphy Exploration & Production Company - USA, LLOG Exploration Offshore, L.L.C. and LLOG Bluewater Holdings, L.L.C.
Exhibit 2.2 to Form 8-K filed June 5, 2019
2.3 Contribution Agreement dated as of October 10, 2018 among Murphy Exploration & Production Company - USA, Petrobras America Inc. and MP Gulf of Mexico, LLC
Exhibit 2.1 to Form 10-K for the year ended December 31, 2018
2.4 Share Sale and Purchase Agreement between Canam Offshore Limited and PTTEP HK Offshore Limited for the sale and purchase of the entire issued share capital of Murphy Sarawak Oil Co., Ltd. and Murphy Sabah Oil Co., Ltd., dated March 21, 2019
Exhibit 10.3 to Form 10-Q filed May 2, 2019
3.1 Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005
Exhibit 3.1 to Form 10-K for the year ended December 31, 2010
3.2 By-Laws of Murphy Oil Corporation, as amended effective February 3, 2016
Exhibit 3.2 to Form 8-K filed February 5, 2016
4.1 Indenture dated as of May 4, 1999 between Murphy Oil Corporation and SunTrust Bank, Nashville, N.A., as trustee
Exhibit 4.2 to Form 10-K for the year ended December 31, 2004
4.2 Supplemental Indenture dated as of May 4, 1999 between Murphy Oil Corporation and SunTrust Bank, Nashville, N.A., as trustee, relating to 7.05% Notes due 2029
Exhibit 4.2 to Form 10-K for the year ended December 31, 2004
4.3 Indenture dated as of May 18, 2012 between Murphy Oil Corporation and U.S. Bank National Association, as trustee
Exhibit 4.1 to Form 8-K filed May 18, 2012
4.4 First Supplemental Indenture dated as of May 18, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 4.00% Notes due 2022
Exhibit 4.2 to Form 8-K filed May 18, 2012
4.5 Second Supplemental Indenture dated as of November 30, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 3.70% Notes due 2022 and 5.125% notes due 2042
Exhibit 4.1 to Form 8-K filed November 30, 2012
4.6 Third Supplemental Indenture dated as of August 17, 2016, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 6.875% Notes due 2024
Exhibit 4.1 to Form 8-K filed August 17, 2016
4.7 Fourth Supplemental Indenture dated as of August 18, 2017, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 5.75% Notes due 2025
Exhibit 4.1 to Form 8-K filed August 18, 2017
4.8 Fifth Supplemental Indenture dated as of November 27, 2019, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, and Wells Fargo Bank, National Association, as series trustee, relating to 5.875% Notes due 2027
Exhibit 4.2 to Form 8-K filed November 27, 2019
4.9 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
Exhibit 4.9 to Form 10-K filed on February 27, 2020
10.1 Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company - International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto
Exhibit 10.1 to Form 8-K filed August 12, 2016
10.2 Third Amendment dated as of November 17, 2017 to Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company - International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto
Exhibit 10.1 to Form 8-K filed November 20, 2017
10.3 Fourth Amendment dated as of October 10, 2018 to Credit Agreement dated as of August 10, 2016 among Murphy Oil Corporation, Murphy Exploration & Production Company - International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto
Exhibit 10.1 to Form 8-K filed October 11, 2018
10.4 Credit Agreement dated as of November 28, 2018 among Murphy Oil Corporation, Murphy Exploration & Production Company - International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto
Exhibit 10.4 to Form 10-K for the year ended December 31, 2018
10.7 Murphy Oil Corporation 2012 Long-Term Incentive Plan
Exhibit A to definitive proxy statement filed March 29, 2012
10.8 Amendment to the Murphy Oil Corporation 2012 Long-Term Incentive Plan
Exhibit 10.8 to Form 10-K filed on February 27, 2020
10.9 Form of employee stock option (2012 Long-Term Plan)
Exhibit 99.1 to Form 10-K for the year ended December 31, 2013
10.10 Form of employee performance-based restricted stock unit grant agreement (2012 Long-Term Plan)
Exhibit 99.2 to Form 10-K for the year ended December 31, 2014
10.11 Form of stock appreciation right (2012 Long-Term Plan)
Exhibit 99.3 to Form 10-Q filed May 7, 2014
10.12 Form of employee time-based restricted stock unit grant agreement (2012 Long-Term Plan)
Exhibit 99.1 to Form 10-Q filed May 7, 2014
10.13 Form of employee time-based restricted stock unit-cash grant agreement (2012 Long-Term Plan)
Exhibit 99.2 to Form 10-Q filed May 7, 2014
10.14 Murphy Oil Corporation 2018 Long-Term Incentive Plan
Exhibit B to definitive proxy statement filed March 23, 2018
10.15 Amendment to the Murphy Oil Corporation 2018 Long-Term Incentive Plan
Exhibit 10.15 to Form 10-K filed on February 27, 2020
10.16 Form of employee performance-based restricted stock unit - stock settled grant agreement (2018 Long-Term Plan)
Exhibit 10.14 to Form 10-K for the year ended December 31, 2018
10.17 Form of employee performance-based restricted stock unit - stock settled grant agreement (2018 Long-Term Plan)
Exhibit 10.17 to Form 10-K filed on February 27, 2020
10.18 Form of employee time-based restricted stock unit - stock settled 3-year grant agreement (2018 Long-Term Plan)
Exhibit 10.15 to Form 10-K for the year ended December 31, 2018
10.19 Form of employee time-based restricted stock unit - stock settled 5-year grant agreement (2018 Long-Term Plan)
Exhibit 10.16 to Form 10-K for the year ended December 31, 2018
10.20 Murphy Oil Corporation 2020 Long-Term Incentive Plan
Exhibit A to definitive proxy statement filed March 30, 2020
*10.21 Form of employee performance-based restricted stock unit - stock settled grant agreement (2020 LTI Plan)
*10.22 Form of employee time-based restricted stock unit - stock settled 3-year grant agreement (2020 LTI Plan)
*10.23 Form of employee time-based restricted stock unit - stock settled 5-year grant agreement (2020 LTI Plan)
*10.24 Form of employee time-based restricted stock unit - cash settled 3-year grant agreement (2020 LTI Plan)
*10.25 Form of employee time-based restricted stock unit - cash settled 5-year grant agreement (2020 LTI Plan)
10.26 Murphy Oil Corporation 2013 Stock Plan for Non-Employee Directors
Exhibit A to definitive proxy statement filed March 22, 2013
10.27 Form of non-employee director restricted stock unit award (2013 NED Plan)
Exhibit 99.2 to Form 10-Q filed November 6, 2013
10.28 Murphy Oil Corporation 2018 Stock Plan for Non-Employee Directors
Exhibit A to definitive proxy statement filed March 23, 2018
10.29 First Amendment to the 2018 Stock Plan for Non-Employee Directors
Exhibit 10.1 to Form 8-K filed April 25, 2018
10.30 Second Amendment to the 2018 Stock Plan for Non-Employee Directors
Exhibit 10.24 to Form 10-K filed on February 27, 2020
10.31 Form of non-employee director restricted stock unit award - stock settled grant agreement (2018 NED Plan)
Exhibit 10.20 to Form 10-K for the year ended December 31, 2018
10.32 Form of non-employee director restricted stock unit award - stock settled grant agreement (2018 NED Plan)
Exhibit 10.26 to Form 10-K filed on February 27, 2020
10.33 Murphy Oil Corporation Non-Qualified Deferred Compensation Plan for Non-Employee Directors
Exhibit 10.6 to Form 10-K for the year ended December 31, 2015
10.34 Tax Matters Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc.
Exhibit 10.1 to Form 8-K filed September 5, 2013
10.35 Employee Matters Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc.
Exhibit 10.3 to Form 8-K filed September 5, 2013
10.36 Trademark License Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc.
Exhibit 10.4 to Form 8-K filed September 5, 2013
*21.1 Subsidiaries of Murphy Oil Corporation
*23.1 Consent of Independent Registered Public Accounting Firm
*23.2 Consent of Ryder Scott Company, L.P.
*23.3 Consent of McDaniel & Associates Consultants Ltd.
*31.1 Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2 Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1 Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*99.1 Ryder Scott reserves audit report for Eagle Ford Shale and Gulf of Mexico
*99.2 Ryder Scott reserves audit report for MP GOM JV
*99.3 McDaniel independent audit report for Canada Onshore and Offshore proved crude oil and natural gas reserves
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
101.LAB XBRL Taxonomy Extension Labels Linkbase Document
101.PRE XBRL Taxonomy Extension Presentation Linkbase