EDGAR 10-K Filing

Company CIK: 717423
Filing Year: 2023
Filename: 717423_10-K_2023_0000717423-23-000015.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, the Corporate segment includes interest income, interest expense, foreign exchange effects, corporate risk management activities and administrative costs not allocated to the exploration and production segments. The Company’s corporate headquarters are located in Houston, Texas following relocation from El Dorado, Arkansas in 2020.
As part of the Company’s underlying operations, the Company is continually monitoring its greenhouse gas (GHG) emissions and impact on the environment as well as other social and environmental aspects of its business. See Sustainability on page 10.
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 32 through 47, 80 through 81, 104 through 106, 110 through 125 and 127 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 produces crude oil, natural gas and natural gas liquids primarily in the U.S. and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide.
During 2022, 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 2022 were in the United States, Canada and Brunei. Murphy is in the process of winding down operations in Australia.
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 2022 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 175,156 barrels of oil equivalent per day, an increase of 4.7% compared to 2021.
For further details on business execution, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” starting on page 32. For further details on 2022 production and sales volume see pages 40 to 43.
United States
In the United States, Murphy produces 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 99,626 barrels of crude oil and natural gas liquids per day and approximately 92 MMCF of natural gas per day in the
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U.S. in 2022. These amounts represented 92.2% of the Company’s total worldwide oil and natural gas liquids and 23.0% of worldwide natural gas production volumes.
Offshore
The Company holds rights to approximately 620 thousand gross acres in the Gulf of Mexico. During 2022, approximately 70% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico, of which approximately 79% was derived from nine fields, including Khaleesi, Mormont, Cascade, Chinook, Neidermeyer, Dalmatian, St. Malo, Kodiak and Lucius. Total average daily production in the Gulf of Mexico in 2022 was 70,008 barrels of crude oil and natural gas liquids and 63 MMCF of natural gas. At December 31, 2022, Murphy had total proved reserves for Gulf of Mexico fields of 162.3 million barrels of oil and natural gas liquids and 124.9 billion cubic feet of natural gas.
The Company has various operated and non-operated fields in the U.S. Gulf of Mexico. The most significant fields are St. Malo, Khaleesi, Mormont, Samurai, Lucius and Dalmatian. The Khaleesi Mormont Samurai development project achieved first oil in 2022 and completed the initial seven well program.
Onshore
The Company holds rights to approximately 133 thousand gross acres in South Texas in the Eagle Ford Shale unconventional oil and natural gas play. During 2022, approximately 30% of total U.S. hydrocarbon production was produced in the Eagle Ford Shale. Total 2022 production in the Eagle Ford Shale area was 29,556 barrels of oil and liquids per day and 28.8 MMCF per day of natural gas. At December 31, 2022, the Company’s proved reserves for the U.S. onshore business totaled 138.9 million barrels of liquids and 210 billion cubic feet of natural gas.
Canada
In Canada, the Company holds working interests in Tupper Montney (100% owned), Kaybob Duvernay (operated), Placid Montney (non-operated) and two non-operated offshore assets - the Hibernia and Terra Nova fields, located 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. In addition, 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 289 thousand gross acres of Kaybob Duvernay and Placid Montney mineral rights. Daily production in 2022 in onshore Canada averaged 4,908 barrels of liquids and 310 MMCF of natural gas. Total onshore Canada proved liquids and natural gas reserves at December 31, 2022, were approximately 21.4 million barrels and 1.9 trillion cubic feet, respectively.
The Company currently has a commitment for 483 million cubic feet per day (MMCFD) of natural gas processing capacity to support production in the Tupper Montney through April 2036, with the commitment reducing to 198 MMCFD for the remainder of the period until November 2040.
Offshore
The Company has an interest in approximately 129 thousand gross acres offshore Canada. Murphy has a 6.5% working interest in Hibernia Main, a 4.3% working interest in Hibernia South Extension and an 18% working interest at Terra Nova.
Oil production in 2022 was 2,812 barrels of oil per day for Hibernia.
During 2022, Terra Nova did not produce as an asset life extension project was being undertaken. Production is expected to resume in the first half of 2023, with estimated asset life extended to 2032.
Total proved reserves for offshore Canada at December 31, 2022 were approximately 22.2 million barrels of liquids and 15.1 billion cubic feet of natural gas.
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Australia
In Australia, the Company has interest in approximately 482 thousand gross acres and holds one offshore exploration permit; Murphy is not the operator. The permit does not have a drilling commitment.
Brazil
The Company holds an interest in nine 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 Potiguar Basin (POT-M-857, POT-M-863 and POT-M-865) with a 30% working interest; in 2022, Murphy transitioned to operator at 100% working interest when Wintershall Dea, the former operator, announced that it would terminate all operations in Brazil.
Murphy’s total acreage position in Brazil as of December 31, 2022 is approximately 2.5 million gross acres, offsetting several major discoveries. There are no well commitments.
Brunei
The Company has a working interest of 8.051% in Block CA-1 as of December 31, 2022. During 2022 the Company sold its 30% working interest in Block CA-2 which was previously classified as held for sale.
Oil production in 2022 was 700 barrels of oil per day for Brunei.
Total proved reserves for our Jagus East discovery in Block CA-1 at December 31, 2022 were approximately 0.5 million barrels of liquids and 0.2 billion cubic feet of natural gas. Block CA-1 covers 1.4 million gross acres.
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 thousand 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 was drilled in 2022 which did not find commercial hydrocarbons.
Vietnam
The Company holds an interest in 7.3 million gross acres, consisting of 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 are awaiting final approval of the development plan. 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 Field Development Plan of the LDV development was adopted by PetroVietnam and being progressed for final approval by the Government.
In Block 15-2/17, the Company is progressing study activity in anticipation of drilling an exploration commitment well by 2024.
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 eight hundred square kilometers of 3D seismic is tentatively scheduled for 2024. In addition, the Company will be seeking to extend the exploration period.
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Proved Reserves
Total proved reserves for crude oil, natural gas liquids and natural gas as of December 31, 2022 are presented in the following table.
Proved Reserves
All Products Crude
Oil Natural Gas
Liquids Natural Gas 4
Proved Developed Reserves: (MMBOE) (MMBBL) (BCF)
United States 264.2 194.4 27.4 254.1
Onshore 121.8 76.6 19.1 156.6
Offshore 1
142.4 117.8 8.3 97.5
Canada 171.3 14.2 2.3 928.8
Onshore 165.0 8.6 2.3 924.8
Offshore 6.3 5.6 - 4.0
Other 0.5 0.4 - 0.2
Total proved developed reserves 436.0 209.0 29.7 1,183.1
Proved Undeveloped Reserves:
United States 92.8 69.2 10.2 80.8
Onshore 52.0 35.5 7.7 53.4
Offshore 2
40.8 33.7 2.5 27.4
Canada 186.5 25.3 1.8 956.0
Onshore 168.0 8.7 1.8 944.9
Offshore 18.5 16.6 - 11.1
Other 0.1 0.1 - -
Total proved undeveloped reserves 279.4 94.6 12.0 1,036.8
Total proved reserves 3
715.4 303.6 41.7 2,219.9
1 Includes proved developed reserves of 15 MMBOE, consisting of 13.7 million barrels of oil (MMBBL) oil, 0.5 MMBBL NGLs and 4.2 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
2 Includes proved undeveloped reserves of 3.2 MMBOE, consisting of 2.8 MMBBL oil, 0.1 MMBBL NGLs and 1.4 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
3 Includes proved reserves of 18.2 MMBOE, consisting of 16.5 MMBBL oil, 0.6 MMBBL NGLs and 5.6 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 74.9 BCF and 43.5 BCF for the U.S. and Canada, respectively, with 0.8 BCF attributable to the noncontrolling interest in MP GOM.
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Murphy Oil’s 2022 total proved reserves and proved undeveloped reserves are reconciled from 2021 as presented in the table below:
(Millions of oil equivalent barrels) 1
Total
Proved
Reserves Total Proved
Undeveloped
Reserves
Beginning of year 716.9 297.7
Revisions of previous estimates (23.6) (8.1)
Extensions and discoveries 80.1 79.4
Improved recovery 5.3 5.3
Conversions to proved developed reserves - (96.9)
Purchases of properties 5.0 2.0
Sale of properties (4.4) -
Production (63.9) -
End of year 2
715.4 279.4
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 18.2 MMBOE and 3.2 MMBOE for total proved and proved undeveloped reserves, respectively, attributable to the noncontrolling interest in MP GOM.
During 2022, Murphy’s total proved reserves decreased by 1.5 million barrels of oil equivalent (MMBOE). The decrease in reserves principally relates to production of 63.9 MMBOE in 2022 and negative price revisions in Tupper Montney from higher commodity prices resulting in increased royalty rates and accelerated royalty incentive payouts. These revisions were offset by extensions of 58.5 MMBOE in onshore Canada, 15.8 MMBOE in offshore U.S. Gulf of Mexico and offshore Canada, and 5.8 MMBOE in the Eagle Ford Shale; improved recovery in the Gulf of Mexico; as well as acquisitions of increased working interest in two producing fields in the Gulf of Mexico and offsetting dispositions in the Gulf of Mexico and the Eagle Ford Shale.
Murphy’s total proved undeveloped reserves at December 31, 2022 decreased 18.3 MMBOE from a year earlier. The proved undeveloped reserves reported in the table as extensions and discoveries during 2022 were predominantly attributable to four areas: the U.S. Gulf of Mexico, the Eagle Ford Shale in South Texas, onshore Canada areas of Tupper Montney and Kaybob Duvernay, and offshore Canada. 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 negative price revisions in Tupper Montney from higher commodity prices resulting in increased royalty rates and accelerated royalty incentive payouts. The majority of the proved undeveloped reserves migration to the proved developed category are attributable to drilling in the Tupper Montney and Kaybob Duvernay, the Gulf of Mexico, and the Eagle Ford Shale. Other proved undeveloped increases resulted from improved recovery as well as an acquisition of increased working interest in two producing fields in the Gulf of Mexico.
The Company spent approximately $770 million in 2022 to convert proved undeveloped reserves to proved developed reserves. In the next three years, the Company expects to spend a range of approximately $350 million to $650 million per year to move current undeveloped proved reserves to the developed category. The anticipated level of spending in 2023 primarily includes drilling and development in the Gulf of Mexico, Eagle Ford Shale and Tupper Montney areas.
At December 31, 2022, proved reserves are included for several development projects, including oil developments at the Eagle Ford Shale in South Texas, deepwater Gulf of Mexico; and Kaybob Duvernay in onshore Canada; as well as natural gas developments at Tupper Montney in onshore Canada. Total proved undeveloped reserves associated with various development projects at December 31, 2022 were approximately 279.4 MMBOE, which represent 39% 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 currently operates deepwater fields in the Gulf of Mexico that have four undeveloped locations that exceed this five-year window. Total reserves associated with the four locations amount to approximately 1% of the Company’s total proved reserves at year-end 2022. The development of certain
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reserves extends beyond five years due to limited well slot availability, thus making it necessary to wait for depletion of other wells prior to initiating further development of these locations or behind-pipe completions with significant capital costs that categorize them as undeveloped.
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 Corporate Reserves (Reserves General Manager) leads the Corporate Reserves group that also includes Corporate reserve engineers and support staff, all of which are independent of the Company’s oil and natural gas operational management and technical personnel. The Reserves General Manager joined Murphy in 2020 and has more than 31 years of industry experience. He has a Bachelor of Science in Mechanical Engineering and is a also a licensed Professional Engineer in the State of Texas. The Reserves General Manager reports to the Executive Vice President and 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 General 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.
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 General Manager and qualified engineering staff from areas of the Company other than the area being audited by third parties. In 2022, 98.0% of the Proved reserves were audited by third-party auditors and they were found to be within the acceptable 10.0% tolerance by each of the third-party firms. Murphy engaged both Ryder Scott Company, L.P. and McDaniel & Associates Consultants Ltd. to perform a reserves audit of 49.9% and 48.1% 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
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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. 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 General Manager. Summaries 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 112 through 119 of this Form 10-K report. 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 SEC. 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, 2022 are shown on pages 41 through 43 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 38 of this Form 10-K report.
Supplemental disclosures relating to oil and natural gas producing activities are reported on pages 110 through 125 of this Form 10-K report.
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Acreage and Well Count
At December 31, 2022, 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 96 24 23 133 119
Gulf of Mexico 60 27 560 271 620 298
Total United States 169 123 584 294 753 417
Canada Onshore 152 116 279 195 431 311
Offshore 101 11 28 1 129 12
Total Canada 253 127 307 196 560 323
Mexico - - 636 254 636 254
Brazil - - 2,453 1,110 2,453 1,110
Australia - - 482 241 482 241
Brunei 2 - 1,446 116 1,448 116
Vietnam - - 7,324 4,571 7,324 4,571
Spain - - 8 1 8 1
Totals 424 250 13,240 6,783 13,664 7,033
Certain acreage held by the Company will expire in the next three years.
Scheduled expirations in 2023 include 241 thousand net acres in Australia, 116 thousand net acres in Brunei, 75 thousand net acres in Brazil, 34 thousand net acres in onshore Canada,16 thousand net acres in the Gulf of Mexico, 5 thousand net acres in Mexico and 1 thousand net acres in Spain.
Acreage currently scheduled to expire in 2024 include 4.5 million net acres in Vietnam, 47 thousand net acres in the Gulf of Mexico and 17 thousand net acres in onshore Canada.
Scheduled expirations in 2025 include 249 thousand net acres in Mexico, 37 thousand net acres in Brazil, 7 thousand net acres in the Gulf of Mexico and 5 thousand net acres in onshore Canada.
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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, 2022.
Oil Wells Natural Gas Wells
Gross Net Gross Net
Country
United States Onshore 1,139 917 30 4
Gulf of Mexico 77 34 13 6
Total United States 1,216 951 43 10
Canada Onshore 18 13 400 338
Offshore 47 5 - -
Total Canada 65 18 400 338
Totals 1,281 969 443 348
Murphy’s net wells drilled and completed 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 - - - - - 0.6 - 0.6
Development 29.1 - 22.1 - - - 51.2 -
Exploration - 0.1 - - - - - 0.1
Development 27.9 - 14.6 - - - 42.5 -
Exploration - 0.4 0.7 - - - 0.7 0.4
Development 21.5 - 8.9 - - - 30.4 -
Murphy’s drilling wells in progress at December 31, 2022 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 - - 15.0 7.0 15.0 7.0
Gulf of Mexico 1.0 0.3 4.0 1.6 5.0 1.9
Canada Onshore - - 5.0 5.0 5.0 5.0
Offshore - - - - - -
Totals 1.0 0.3 24.0 13.6 25.0 13.9
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Sustainability
Environment and Climate Change
We understand that our industry, and the use of our products, create emissions - which raise climate change concerns. At the same time, access to affordable, reliable energy is essential to improving the world’s quality of life and the functioning of the global economy. We believe that as the energy economy transitions, oil and natural gas will continue to play a vital role in the long-term energy mix.
We are committed to reducing our GHG emissions and are focused on understanding and mitigating our climate change risks. To guide our climate change strategy, Murphy has adopted a climate change position, and we are setting meaningful emissions reduction goals. In 2021, we endorsed the goal of eliminating routine flaring by 2030, under the current World Bank definition of routine flaring. This adds to the Company’s previously established GHG emissions intensity reduction target of 15% to 20% by 2030 from our 2019 level, excluding our discontinued and divested Malaysia operations.
Murphy recognizes that emissions are only one element of our total environmental footprint. Protecting natural resources is also an important factor in our overall sustainability efforts. See our discussion of Climate Change and Emissions on page 48.
Further, 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 GHG 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 a 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 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 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 of 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. 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.
These include, in the Gulf of Mexico, well design, well control, casing, cementing, real-time monitoring and subsea containment, among other items. Under applicable requirements, BOEM evaluates the financial strength and reliability of lessees and operators active on the Outer Continental Shelf, including the Gulf of Mexico. If the BOEM determines 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.
Air emissions and climate change. The U.S. Clean Air Act 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 gas sector due to their association
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with climate change. In addition, international climate efforts, including the 2015 “Paris Agreement” and the 2021 and 2022 Conferences of the Parties of the UN Framework Convention on Climate Change (COP26 and COP27, respectively), have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs.
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 limitations or further regulation of GHG, such as a cap and trade system, technology mandate, emissions tax, or expanded reporting requirements, could cause the Company to restrict operations, curtail demand for hydrocarbons generally, and/or cause costs to increase. Examples of cost increases include 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.
As noted above, Murphy is subject to various laws and regulatory regimes governing similar matters in other jurisdictions in which it operates. More specifically, Murphy’s operations in Canada are subject to and conducted under Canadian laws and regulations that address many of the same environmental, health and safety issues as those in the U.S., including, without limitation, pollution and contamination, air quality and emissions, water discharges and other health and safety concerns.
Health and Safety
Murphy’s commitment to safety is strong, and so are our actions to protect our workforce and communities. Our employees are our most valuable asset. Murphy strives to achieve incident-free operations through continuous improvement processes managed by the Company’s Health, Safety, Environment (HSE) Management System (HSE-MS), which engages all personnel, contractors and partners associated with Murphy operations and facilities, and provides a consistent method for integrating HSE concepts into our procedures and programs. We work hard to build a culture of safety across our organization, with regular training, exercise drills and key targeted safety initiatives.
Response to COVID-19. During the COVID-19 pandemic, a proactive approach was taken by Murphy and we adopted strict protocols to protect our employees and their families, contractors and the communities in which we work from the virus. Our response program was led by our Incident Management Team (IMT), under the guidance of our Crisis Management Team (CMT), leveraging the advice and recommendations of infectious disease experts and establishing safety protocols for all workers.
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 Occupational Health and Safety (OH&S) Legislation, the provincially-administered Occupational Health and Safety Act (Alberta), the Workers Compensation Act (British Columbia) and the Workplace Hazardous Materials Information System (WHMIS).
PART I
Item 1. Business - Continued
Human Capital Management
At Murphy, we believe in providing energy that empowers people, and that is what our 691 employees do every day. As of December 31, 2022, we had 400 office-based employees and 291 field employees, all of whom are guided by our mission, vision, values and behaviors. Together with the Executive Leadership Team, the Vice President of Human Resources and Administration, who reports directly to our President and Chief Executive Officer, 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, 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
•Diversity, Equity and Inclusion
•Health and Welfare Benefits
The Board of Directors receives related updates from management on a regular basis including the review of compensation, benefits, succession and talent development and 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 performance-based bonus programs, while maintaining the best interest of stockholders. 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. We believe our current practices align our employees’ compensation with the interests of our stockholders, and support our focus on cash flow generation, capital return and environmental stewardship. For further detail on the Company’s compensation framework please see the Compensation Discussion and Analysis section of the forthcoming Proxy Statement relating to the Annual Meeting of Stockholders on May 10, 2023.
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 the 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 is tied to Company and stockholder interests
All employees’ performance is evaluated at least 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 contributions toward executing our company’s goals/business strategy.
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. We also administer mandatory compliance training for our employees through My Murphy Learning, with a 100% utilization. Further, we strive to empower our leadership, so we sponsor several programs to address career advancement for emerging leaders. 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 for career advancement. Murphy holds internal technical ideas forums each year designed to share best practice and technical advances across the Company, including safety and environmental topics.
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Item 1. Business - Continued
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 their alignment with Murphy’s mission, vision, values and behaviors.
To monitor the effectiveness of our human capital investment and development programs, we track voluntary turnover. This data is shared on a regular basis with our Executive Leadership Team, who use it in addition to other pertinent data to develop our human capital strategy. In 2022, our voluntary employee turnover rate was 10.5%.
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 subsidized benefits that are competitive and aligned to Murphy’s mission, vision, values and behaviors. We also believe that the well-being 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.
In addition, we offer an Employee Assistance Program (EAP) that provides confidential assistance to employees and their immediate family members for mental and physical well-being, 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.
Diversity, Equity and Inclusion
We are committed to fostering work environments that value diversity, equity and inclusion (DE&I). 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 also support interest-based groups such as sports, hobbies and charity volunteering. We welcome our employees’ differences, experiences and beliefs and we are investing in a more productive, engaged, diverse and inclusive workforce. The Board of Directors receives DE&I updates on Demographic Data, Strategic Partnerships, Recruiting Strategies and Programs from management on a regular cadence.
We seek input and program recommendations from our DE&I Committee with the support of the Executive Leadership team and through the sponsorship of our Vice President, Human Resources and Administration. Our DE&I Committee consists of diverse employees at various levels from across the organization that share a passion for DE&I. Our Board currently includes three women directors with at least one female director on each committee. Our Nominating and Governance Committee is actively focused on DE&I issues as part of its overall mandate.
Female Representation (U.S. and International)
December 31, 2022
Executive and Senior Level Managers 16 %
First- and Mid-Level Managers 23 %
Professionals 35 %
Other (Administrative Support and Field) 5 %
Total 21 %
Minority 1 Representation (U.S.-Based Only)
December 31, 2022
Executive and Senior Level Managers 26 %
First- and Mid-Level Managers 26 %
Professionals 39 %
Other (Administrative Support and Field) 30 %
Total 33 %
1 As defined by the U.S. Equal Employment Opportunity Commission (EEOC).
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Item 1. Business - Continued
We believe that it is important we attract employees with diverse backgrounds where we operate and are focusing on attracting and retaining women and minorities in our workforce ensuring a vibrant talent pipeline.
Environmental, Social and Governance (ESG) Disclosure
We publish an annual sustainability report according to internationally recognized ESG reporting frameworks and standards, including Sustainability Accounting Standards Board (SASB), Task Force on Climate-related Financial Disclosures (TCFD), Global Reporting Initiative (GRI): Core option, Ipieca and American Petroleum Institute (API).
As this is an area of continual improvement across our industry, we strive to update our disclosures in line with operating developments and with emerging best practice ESG reporting standards. In 2022, we published our fourth annual sustainability report, located on the Company’s website.
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, or incorporated into, 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.
PART I

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ITEM 1A. RISK FACTORS
Item 1A. RISK FACTORS
The Company faces risks in the normal course of business and through global, regional and local events that could have an adverse impact on its reputation, operations, and financial performance. The Board of Directors exercises oversight of the Company’s enterprise risk management program, which includes strategic, operational and financial matters, as well as compliance and legal risks. The Board of Directors receives updates annually on the risk management processes.
The following are some important factors that could cause the Company’s actual results to differ materially from those projected in any forward-looking statements. If any of the events or circumstances described in any of the following risk factors occurs, our business, results of operations and/or financial condition could be materially and adversely affected, and our actual results may differ materially from those contemplated in any forward-looking statements we make in any public disclosures.
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, cash flows and financial condition.
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 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, Russia, to agree to maintain or adjust production levels;
•the production levels of non-OPEC countries, including, amongst others, production levels in the shale plays in the United States;
•political instability or armed conflict in oil and natural gas producing regions, such as the Russia-Ukraine conflict;
•the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
•changes in weather patterns and climate, including those that may result from climate change;
•natural disasters such as hurricanes and tornadoes, including those that may result from climate change;
•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 and focus on climate-change;
•technological advances affecting energy consumption and energy supply;
•increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and considerations including climate change and the transition to a lower carbon economy;
•domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use or generation of alternative energy sources and fuels; and
•general economic conditions worldwide, including inflationary conditions and related governmental policies and interventions.
West Texas Intermediate (WTI) crude oil prices averaged $94 per barrel in 2022, compared to $68 in 2021, $39 in 2020 and $57 in 2019. 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
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Item 1A. Risk Factors - Continued
common crude oil indices used to price the Company’s crude include Mars, WTI Houston (MEH), Heavy Louisiana Sweet (HLS) and Brent.
The average New York Mercantile Exchange (NYMEX) natural gas sales price was $6.38 per million British Thermal Units (MMBTU) in 2022, compared to $3.84 in 2021 and $1.99 in 2020. The Company also has exposure to the Canadian benchmark natural gas price, AECO, which averaged US$4.09 per MMBTU in 2022, compared to US$2.89 in 2021 and US$1.66 in 2020. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section on page 54 and spot contracts providing exposure to other market prices at specific sales points such as Malin (Oregon, U.S.) and Dawn (Ontario, Canada).
Lower prices, should they occur, will materially and adversely affect our results of operations, cash flows and financial condition. 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 may hedge 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.
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, as a result of low oil and natural gas prices, 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.
See Note L for additional information on the derivative instruments used to manage certain risks related to commodity prices.
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. To the extent that the Company enters into these contracts and in the event that prices for oil and natural gas increase in future periods, the Company will not fully benefit from the price improvement on all production. See Note L for additional information on the derivative instruments used to manage certain risks related to commodity prices.
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Item 1A. Risk Factors - Continued
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 major integrated oil companies, independent producers of oil and natural gas, and state-owned foreign oil companies. Many of the major integrated and state-owned 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. Within the industry, Murphy competes for, among other things, 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 hole expense, which has in the past and may in the future, adversely affect our results of operations. The Company’s strategy is to participate in three to five exploration wells per year. In 2022, the Company participated in two exploration wells, the Cutthroat well located in Brazil and the Tulum-1EXP well located in Mexico, that failed to encounter commercial hydrocarbons. In addition, in December of 2022, the Company commenced drilling of the Oso-1 well in the Gulf of Mexico, with drilling to continue through the first quarter of 2023. The Company has budgeted $100 million for its 2023 exploration program, which includes finishing the Oso-1 well and drilling two additional Gulf of Mexico operated exploration wells.
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 must find, acquire or develop, and produce 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.
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 110 through 119 have been prepared according to the 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 2022, 98.0% 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.
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Item 1A. Risk Factors - Continued
The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2022, and including noncontrolling interests, approximately 31% of the Company’s crude oil and condensate proved reserves, 29% of natural gas liquids proved reserves and 47% 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 123 and 124 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 2022, approximately 21% of the Company’s total production was at fields operated by others, while at December 31, 2022, approximately 15% 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, severe weather events, physical security risks and risks normally associated with the exploration and production of oil and natural gas, which could become more significant as a result of climate change.
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 GHG in the earth’s atmosphere may produce climate changes that increase significant weather events, such as
PART I
Item 1A. Risk Factors - Continued
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 to our operations are not fully insured.
In addition, certain customer and supplier assets, such as storage terminals, processing facilities, refineries and pipelines, are located in areas that may be prone to severe weather events, including hurricanes, winter storms, floods and major tropical storms. Severe weather events that significantly affect facilities belonging to such customers or suppliers may reduce demand for our products and interrupt our ability to bring products to market and may therefore materially and adversely affect our results of operations, cash flows and financial condition, even if our own facilities escape significant damage.
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, provincial and local environmental, health and safety laws, regulations, governmental actions and permit requirements, 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 GHG emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. The laws, regulations, governmental actions and permit requirements are subject to frequent change and have tended to become stricter over time and at times may be motivated by political considerations. They can impose permitting and financial assurance obligations, as well as operational controls and/or siting constraints on our business, and can result in additional capital and operating expenditures. 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 U.S. Onshore operations and certain regulatory bodies in Canada may decide to revoke permits or pause the issuance of permits as a result of non-compliance with, or litigation related to, environmental, health and safety laws and regulations. Compliance with such regulations could result in capital investment which would reduce the Company’s net cash flows and profitability.
Murphy also could be subject to strict liability for environmental contamination in various jurisdictions where it operates, 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.
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 Kaybob Duvernay and Tupper Montney in Western Canada. Texas law imposes permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations, as well as public disclosure of certain information regarding the components used in the hydraulic fracturing process. Regulations in the provinces of British Columbia and Alberta also govern various aspects of hydraulic fracturing activities under their jurisdictions. It is possible that Texas, other states in which we may conduct fracturing in the future, the U.S., Canadian provinces and certain municipalities may 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,
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Item 1A. Risk Factors - Continued
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 addition, 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. These include, in the Gulf of Mexico, well design, well control, casing, cementing, real-time monitoring, and subsea containment, among other items. Under applicable requirements, BOEM evaluates the financial strength and reliability of lessees and operators active on the OCS. If the BOEM determines 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 addition, various executive orders by the current presidential administration and the Department of Interior over the course of 2021 regarding a temporary suspension of normal-course issuance of permits for fossil fuel development on federal lands and a pause on new oil and gas leases on public lands and offshore waters, and the Secretary of Interior’s related review of permitting and leasing practices, could adversely impact Murphy’s operations. Despite the pauses on oil and gas leases in 2021, in August 2022, the Inflation Reduction Act was passed by the U.S. Congress and included provisions which required the Department of Interior to hold previously announced offshore lease sales in the Gulf of Mexico and Alaska within two years. These developments demonstrate the uncertainty regarding the current presidential administration’s approach to oil and gas leasing and permitting. For further details, 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.”
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Item 1A. Risk Factors - Continued
We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and sustainability considerations, including climate change and the transition to a lower carbon economy.
Opposition toward oil and gas drilling, development, and production activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and nongovernmental organizations and other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.
Activism may continue to increase regardless of whether the current presidential administration in the U.S. is perceived to be following, or actually follows, through on the current president’s campaign commitments to promote decreased fossil fuel exploration and production in the U.S, including as a result of the administration’s environmental and climate change executive orders described earlier in this 10-K. Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In addition, a change in public sentiment regarding the oil and gas industry could result in a reduction in the demand for our products or otherwise affect our results of operations or financial condition.
While the Company has been named a co-defendant with other oil and gas companies in lawsuits related to climate change, these lawsuits have not resulted in, and are not currently expected to result in, material liability for the Company. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition. For further details on risks related to legal proceedings more generally, see “Risk Factors - General Risk Factors - Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.”
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 2022, the Company entered into an $800 million revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility and will expire in November 2027. As of December 31, 2022, the Company had no outstanding borrowings under the RCF. See Note G for further details on the RCF.
The Company’s ability to obtain additional financing is affected by a number of factors, including the market environment, our operating and financial performance, investor sentiment, our ability to incur additional debt in compliance with agreements governing our outstanding debt, and the Company’s credit ratings. 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 any additional indebtedness we incur, and potentially require the Company to post additional letters of credit or other forms of collateral for certain obligations. Murphy partially manages this risk through borrowing at fixed rates wherever possible; however, rates when refinancing or raising new capital are determined by factors outside of the Company’s control.
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Item 1A. Risk Factors - Continued
Further, changes in investors’ sentiment or view of risk of the exploration and production industry, including as a result of concerns over climate change, could adversely impact the availability of future financing. Specifically, certain financial institutions (including certain investment advisors and sovereign wealth, pension and endowment funds), in response to concerns related to climate change and the requests and other influence of environmental groups and similar stakeholders, have elected to shift some or all of their investments away from fossil fuel-related sectors, and additional financial institutions and other investors may elect to do likewise in the future. As a result, fewer financial institutions and other investors may be willing to invest in, and provide capital to, companies in the oil and gas sector, which, in turn, could adversely impact our cost of capital.
In 2022, the Company undertook several actions to reduce overall debt. Murphy plans to continue with the Company’s deleveraging initiatives, but there can be no assurance that these efforts will be successful and, if not, the Company’s financial conditions and prospects could be adversely affected. See Note G for information regarding the Company’s outstanding debt as of December 31, 2022.
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 L 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 gas industry. In addition, periods of inflationary pressure in the wider economy, as seen during 2022, can also lead to a similar increase in the cost of goods and services for the Company. Murphy has a dedicated procurement department focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from increasing price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher prices.
PART I
Item 1A. Risk Factors - Continued
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; and
• 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.
As the COVID-19 pandemic has evolved from its emergence in early 2020, so has its global impact. In 2020 the spread of COVID-19 led to disruption in the global economy and weakness in demand in crude oil, natural gas liquids and natural gas, which applied downward pressure on global commodity prices. The combination of vaccine availability and the relaxation of government-imposed lockdowns in 2021 led to a rebound in global economic activity in 2021, which continued throughout 2022.
However, the future impact of COVID-19, or that of any other pandemic, cannot be predicted and any resurgence of disease may cause additional volatility in 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 or other 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 commitments 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.
The COVID-19 or other pandemic could also 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.
We continue to work with our stakeholders (including customers, employees, suppliers, financial and lending institutions and local communities) to address the COVID-19 pandemic responsibly. 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 continues to exercise financial discipline in managing costs and capital expenditures.
We cannot predict the ongoing impact of the COVID-19 or other pandemic. The extent to which the COVID-19 or other health pandemics or epidemics may impact our results will depend on future developments, including, among other factors, the duration and spread of the virus and its variants, availability, acceptance and effectiveness of vaccines along with related travel advisories, quarantines and restrictions, the recovery time of
PART I
Item 1A. Risk Factors - Continued
the disrupted supply chains and industries, the impact of labor market interruptions, and the impact of government interventions.
Changes in U.S. and international tax rules and regulations, or interpretations thereof, may materially and adversely affect our cash flows, results of operations and financial condition.
We are subject to income- and non-income-based taxes in the United States under federal, state and local jurisdictions and in the foreign jurisdictions in which we operate. Tax laws, regulations and administrative practices in various jurisdictions may be subject to significant change, with or without advance notice, due to economic, political and other conditions, and significant judgment is required in evaluating and estimating our provision and accruals for these taxes. Our tax liabilities could be affected by numerous factors, such as changes in tax, accounting and other laws, regulations, administrative practices, principles and interpretations, the mix and level or earnings in a given taxing jurisdiction or our ownership or capital structure. For example, on August 16, 2022, the United States enacted the Inflation Reduction Act of 2022, which is highly complex, subject to interpretation and contains significant changes to U.S. tax law, including, but not limited to, a 15% corporate book minimum tax for taxpayers with adjusted financial statement income in excess of $1 billion and a 1% excise tax on certain stock repurchases made after December 31, 2022. The U.S. Department of the Treasury and the IRS are expected to release further regulations and interpretive guidance implementing the legislation contained in the Inflation Reduction Act of 2022, but the details and timing of such regulations are subject to uncertainty at this time. The tax provisions of the Inflation Reduction Act of 2022 that may apply to us are generally effective in 2023 or later and therefore tax impacts to us in 2022 were immaterial. We continue to analyze the potential impact of the Inflation Reduction Act of 2022 on our consolidated financial statements and to monitor guidance to be issued by the U.S. Department of the Treasury. However, it is possible that the enactment of changes in the U.S. corporate tax system, including in connection with the Inflation Reduction Act of 2022, could have a material effect on our consolidated cash taxes in the future.
Murphy’s Information Technology environment may be exposed to cyber threats.
The oil and 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, communicate internally and externally, 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, and our cybersecurity training and policies, to protect and secure intellectual property, strategic plans, customer information, and personally identifiable information, such as employee information.
A failure of our cyber infrastructure or 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 three key elements:
• People - Security awareness education and readiness-testing throughout the year for employees and contractors;
• Process - Incorporating “cyber awareness” in our day to day processes and maturing key controls such as recurring internal and external cyber risk assessments, physical and digital asset protection, and security vulnerability remediation via preventative and detective measures; and
• Technology - Investing in industry aligned security technology and threat intelligence capabilities.
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.
PART I
Item 1A. Risk Factors - Continued
Murphy’s operations and earnings have been and will continue to be affected by domestic and worldwide political developments.
From time to time, some governments intervene in the market for crude oil and natural gas produced in their countries through such actions as 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 the current U.S. president in January 2021, the U.S. Secretary of the Interior issued Order No. 3395 on January 20, 2021. This order served to potentially impact the timing of issuance of oil and gas leases, lease amendments and extension, and drilling permits on federal lands and offshore waters. However, 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 regime 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 current presidential administration has pursued other initiatives related to environmental, health and safety standards applicable to the oil and gas industry. These include an executive order in January 2021 that directed the Secretary of the Interior to halt indefinitely new oil and gas leases on federal lands and offshore waters pending a since-completed review by the Secretary of the Interior of federal oil and gas permitting and leasing practices; however, a June 2021 preliminary injunction in the U.S. District Court for the Western District of Louisiana barred the current presidential administration from implementing the pause in new federal oil and gas leases. This executive order also set forth other initiatives and goals, including procurement of carbon pollution-free electricity, elimination of fossil fuel subsidies, a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Another executive order from January 2021 called for a climate change-focused review of regulations and other executive actions promulgated, issued or adopted during the prior presidential administration. In August 2022, the Inflation Reduction Act was passed by the U.S. Congress and included provisions which required the Department of Interior to hold previously announced offshore lease sales in the Gulf of Mexico and Alaska within two years. These developments demonstrate the uncertainty regarding the current presidential administration’s approach to oil and gas leasing and permitting.
In March 2022, the SEC proposed rules requiring disclosure of a range of climate change-related information, including, among other things, companies’ climate change risk management; short- medium- and long-term climate-related financial risks; and disclosure of Scope 1, Scope 2 and (for certain companies) Scope 3 emissions. The SEC’s proposed climate disclosure rules have not yet been finalized, but implementation of the rules as proposed could be costly and time consuming.
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 of these changes on our future consolidated financial condition, results of operations or cash flows cannot be predicted.
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 law 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. As of December 31, 2022, 0.1% of the Company’s proved reserves, as defined by the SEC, were located in countries other than the U.S. and Canada.
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
PART I
Item 1A. Risk Factors - Continued
fracturing with the desire to minimize the emission of GHG 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 and other similar anti-corruption compliance statutes in the jurisdictions in which we operate.
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 $450 million per occurrence ($850 million for U.S. 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.
Murphy could face long-term challenges to the fossil fuels business model reducing demand and price for hydrocarbon fuels.
Murphy’s business model may come under more pressure from changing environmental and social trends and the related global demands for non-fossil fuel energy sources. This demand in alternative forms of energy may cause the price of our products to become more volatile and decline. Further, a reduction in demand for fossil fuels could adversely impact the availability of future financing. As part of Murphy’s strategy review process, the Company reviews hydrocarbon demand forecasts and assesses the impact on its business model and, plans and future estimates of reserves. In addition, the Company evaluates other lower-carbon technologies that could complement our existing assets, strategy and competencies as part of its long-term capital allocation strategy. 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 GHG emissions. The Paris Agreement and subsequently yearly “conferences of the parties” to the Paris Agreement have resulted in commitments from many countries to reduce GHG emissions and have called for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Most recently, in November 2022, the international community gathered in Egypt at the 27th Conference of the Parties on the UN Framework Convention on Climate Change (COP27), during which multiple announcements were made, including the EPA’s announcement of more stringent revisions to previously proposed methane emissions rules for the oil and gas sector. The previously proposed rules and EPA’s November 2022 revisions, establish requirements for methane emissions from existing and modified oil and gas sources and impose additional requirements for new sources. In addition, the federal government could issue various executive orders that may result in additional laws, rules and regulations in the area of climate change. It is possible that the Paris Agreement, COP27, government executive orders and other such initiatives, including foreign, federal and state laws, rules or regulations related to GHG 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.
PART I
Item 1A. Risk Factors - Continued
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, environmental and/or property damages, climate change 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.
PART I

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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, 2022.

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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 110 to 125 and in Note D beginning on page 80.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. LEGAL PROCEEDINGS
Discussion of the Company’s legal proceedings are included in Note R beginning on page 103.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
PART I
Information about our Executive Officers
Present corporate office, length of service in office and age at February 1, 2023 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 61; President and Chief Executive Officer since 2013. Mr. Jenkins served as Chief Operating Officer from 2012 to 2013.
Thomas J. Mireles - Age 50; Executive Vice President and Chief Financial Officer since 2022. Mr. Mireles was Senior Vice President, Technical Services from 2018 to 2022. Mr. Mireles also served as the Senior Vice President, Eastern Hemisphere of Murphy Exploration & Production Company from 2016 to 2018.
Eric M. Hambly - Age 48; 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 58; 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.
Daniel R. Hanchera - Age 65; Senior Vice President, Business Development since December 2022. Mr. Hanchera served as Senior Vice President, Business Development of Murphy Exploration & Production Company from 2014 to 2022. He also served as Vice President, Business Development and Planning of Murphy Exploration & Production Company from 2009 to 2014.
John B. Gardner - Age 54; Vice President, Marketing and Supply Chain since 2022. Mr. Gardner was Vice President and Treasurer from 2015 to 2022 and served as Treasurer from 2013 to 2015.
Leyster L. Jumawan - Age 46; Vice President, Corporate Planning and Treasurer since July 2022. Mr. Jumawan was Assistant Treasurer from 2017 to 2022.
Maria A. Martinez - Age 48; Vice President, Human Resources and Administration since 2018. Ms. Martinez was Vice President, Human Resources of Murphy Exploration & Production Company from 2013 to 2018.
Meenambigai Palanivelu - Age 49; Vice President, Sustainability since February 2023. Ms. Palanivelu was Director, Sustainability from 2020 to 2023. Ms. Palanivelu also served as the General Manager, Planning and Performance from 2019 to 2020 and General Manager, Finance Operating Model Program Management Office from 2017 to 2019.
Louis W. Utsch - Age 57; Vice President, Tax since 2018.
Paul D. Vaughan - Age 56, Vice President and Controller since July 2022. Mr. Vaughan was Vice President and Controller, U.S., Central and South America of Murphy Exploration & Production Company from 2017 to 2022.
Kelly L. Whitley - Age 57; 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 2,063 stockholders of record as of December 31, 2022. Information on dividends per share by quarter for 2022 and 2021 are reported on page 126 of this Form 10-K report.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued
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, 2017 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group. XOP Index reports a comprehensive view of the oil and gas exploration and production segment of the S&P Total Market Index which is more comparable for the Company than the S&P 500 Index. 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:
APA Corporation Hess Corporation PDC Energy, Inc.
Coterra Energy Inc. Kosmos Energy Ltd. Range Resources Corporation
CNX Resources Corporation Marathon Oil Corporation Southwestern Energy Company
Devon Energy Corporation Ovintiv Inc. Talos Energy Inc.
2017 2018 2019 2020 2021 2022
Murphy Oil Corporation 100 78 93 44 97 164
Peer Group 100 72 79 62 110 169
S&P 500 Index 100 96 126 149 192 157
XOP Index 100 81 90 58 109 173
PART II

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. RESERVED

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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 2022, a combination of demand recovery from the COVID-19 pandemic, geopolitical uncertainty and market disruption from the Russia/Ukraine conflict and lack of investment in the exploration and production sector contributed to increased crude oil and natural gas benchmark prices compared to 2021. Prices declined in the second half of 2022, due to increased supply related to the Strategic Petroleum Reserve oil release and ongoing concerns related to a possible economic slowdown and demand from China.
Similar to the overall inflation in the wider economy, the oil and gas industry, and hence the Company, is observing higher costs for goods and services used in exploration and production operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs.
Significant Company operating and financial highlights during and at the end of 2022 were as follows:
•Generated net income of $965 million and $2,180.2 million of net cash provided by operating activities and $1,070.8 million of adjusted cash flow1;
•Produced 175 thousand barrels of oil equivalent (BOE) per day (167 thousand excluding noncontrolling interest, NCI) and completed the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico with seven wells brought online;
•Acquired additional working interest in non-operated Lucius and Kodiak fields in the Gulf of Mexico for $128.5 million;
•Announced capital allocation framework 2 and reduced total debt by approximately $650 million, a 26% debt reduction in the year;
•Doubled the cash dividend since the fourth quarter of 2021 to $1.00 per share annualized; and
•Achieved 98% total proved reserve replacement with year-end proved reserves of 715.4 million barrels of oil equivalent (697.2 million excluding NCI).
1 Adjusted cash flow is a non-GAAP financial measure calculated as cash flow from operations less capital expenditures ($1,109.4 million). Management believes adjusted cash flow is important to provide as it is used by management to evaluate the Company’s ability to generate additional cash from business operations after providing for capital investments. Adjusted cash flow is a non-GAAP financial measure and should not be considered a substitute for other financial measures as determined in accordance with accounting principles generally accepted in the United States of America. Additionally, our definition of adjusted cash flow is limited and does not represent residual cash flows available for other discretionary expenditures as the measure does not deduct the payments required for debt service and other obligations. Therefore, we believe it is important to view adjusted cash flow as supplemental to our entire statement of cash flows.
2 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.
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 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 and expenses related to exploration, administration and for capital borrowed from lending institutions and note holders.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In 2022, liquids from continuing operations represented approximately 62% of total hydrocarbons produced on an energy equivalent basis. In 2023, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 63%. If the prices for crude oil and natural gas are lower in 2023 or beyond, this will have an unfavorable impact on the Company’s operating profits; likewise, if prices are higher, this will have a favorable impact. 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 were higher in 2022 compared to the 2021 and 2020 periods. The sales price of a barrel of West Texas Intermediate (WTI) crude oil averaged $94.23 in 2022, $67.91 in 2021 and $39.40 in 2020. In 2023, the WTI price has thus far been below the comparable period in 2022, however, higher than the comparable period 2021.
WTI average price for 2022 increased 39% over the prior year principally as a result of demand recovery from the COVID-19 pandemic, geopolitical uncertainty and market disruption following the Russia/Ukraine conflict and market concerns over supply shortfalls as discussed above.
The most common crude oil indices used to price the Company’s crude include Mars, WTI Houston (MEH), Heavy Louisiana Sweet (HLS) and Brent.
The New York Mercantile Exchange (NYMEX) natural gas price per million British Thermal Units (MMBTU) averaged $6.38 in 2022, $3.84 in 2021 and $1.99 in 2020. The 2022 NYMEX natural gas price was higher compared to 2021 and NYMEX prices in 2023 have thus far been below the comparable period in 2022.
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)
2022 2021 2020
Income (loss) from continuing operations before income taxes $ 1,450.3 $ 42.9 $ (1,549.0)
Net income (loss) attributable to Murphy 965.0 (73.7) (1,148.8)
Diluted EPS 6.13 (0.48) (7.48)
Income (Loss) from continuing operations attributable to Murphy 967.1 (72.4) (1,141.6)
Diluted EPS 6.14 (0.47) (7.43)
(Loss) income from discontinued operations (2.1) (1.2) (7.2)
Diluted EPS (0.01) (0.01) (0.05)
For the year ended December 31, 2022, the Company produced 175 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $1,183.2 million in capital expenditures (on a value of work done basis) for the year ended December 31, 2022, which included $25.9 million attributable to noncontrolling interest and $128.5 million for capital acquisitions. The Company reported net income from continuing operations of $1,140.8 million for the year ended December 31, 2022. This amount includes income attributable to noncontrolling interest of $173.7 million, after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $169.6 million and after-tax losses on contingent consideration (see Note P) of $61.6 million.
In 2022, the Company achieved first production from the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico and acquired a 3.4% working interest in the Lucius field and an 11.0% working interest in the Kodiak field in the Gulf of Mexico, with both acquisitions having no noncontrolling interests.
For the year ended December 31, 2021, the Company produced 167 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations. The Company invested $711.2 million in capital expenditures (on a value of work done basis) for the year ended December 31, 2021, which included $23.0 million attributable to noncontrolling interest and $17.3 million to fund the development of the King’s Quay
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
floating production system (FPS). The Company reported net income from continuing operations of $48.8 million (which included post tax impairment charges of $151.5 million and income attributable to noncontrolling interest of $121.2 million) for the year ended December 31, 2021.
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 Adjusted 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.
Year Ended December 31,
(Millions of dollars, except per barrel of oil equivalents sold) 2022 2021 2020
Net (loss) income attributable to Murphy (GAAP) $ 965.0 $ (73.7) $ (1,148.8)
Income tax expense (benefit) 309.5 (5.9) (293.7)
Interest expense, net 150.8 221.8 169.4
Depreciation, depletion and amortization expense ¹ 748.2 760.6 932.6
EBITDA attributable to Murphy (Non-GAAP) 2,173.5 902.8 (340.5)
Mark-to-market (gain) loss on derivative instruments (214.7) 112.1 69.3
Mark-to-market loss (gain) on contingent consideration 78.3 63.2 (13.8)
Foreign exchange (gain) loss (23.0) (1.0) 0.7
Loss (gain) on sale of assets ¹ (14.5) - -
Accretion of asset retirement obligations ¹ 40.9 41.1 42.1
Write-off of previously suspended exploration wells 22.7 - -
Asset retirement obligation losses (gains) 30.8 (71.8) (2.8)
Discontinued operations loss 2.1 1.2 7.2
Impairment of assets 1
- 196.3 1,072.5
Unutilized rig charges - 8.7 16.0
Restructuring expenses - - 50.0
Inventory loss - - 8.3
Insurance Proceeds - - (1.7)
Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 2,096.1 $ 1,252.6 $ 907.3
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) 60,837 57,476 60,189
Adjusted EBITDA per barrel of oil equivalents sold $ 34.45 $ 21.79 $ 15.07
1 Depreciation, depletion and amortization expense, impairment of assets, loss (gain) on sale of sale of assets and accretion of asset retirement obligations 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, 2022, are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and other activities follow the table.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
A summary of Net income (loss) is presented in the following table.
(Millions of dollars)
2022 2021 2020
Exploration and production - continuing operations
United States $ 1,521.9 $ 766.3 $ (1,014.3)
Canada 134.2 (16.1) (35.0)
Other International (77.0) (33.5) (85.6)
Total exploration and production - continuing operations 1,579.1 716.7 (1,134.9)
Corporate and other (438.3) (668.0) (120.3)
Income (loss) from continuing operations 1,140.8 48.7 (1,255.2)
(Loss) income from discontinued operations (2.1) (1.2) (7.2)
Net income (loss) including noncontrolling interest 1,138.7 47.5 (1,262.4)
Net income (loss) attributable to noncontrolling interest 173.7 121.2 (113.7)
Net income (loss) attributable to Murphy $ 965.0 $ (73.7) $ (1,148.7)
A summary of oil and natural gas revenues is presented in the following table.
(Millions of dollars)
2022 2021 2020
United States Oil and natural gas liquids $ 3,210.3 $ 2,199.7 $ 1,335.8
Natural gas 225.2 121.7 69.4
Canada Oil and natural gas liquids 267.5 228.9 174.0
Natural gas 312.6 245.9 170.6
Other Oil 22.8 4.9 1.8
Total oil and natural gas revenues $ 4,038.4 $ 2,801.1 $ 1,751.6
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.
2022 vs 2021
The results of operations in this section 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) from continuing operations recorded earnings of $1,579.1 million in 2022 compared to earnings of $716.7 million million in 2021. Results were favorable $862.4 million in 2022 compared to 2021 primarily due to higher oil, natural gas liquid and natural gas prices and volumes, lower impairment charges and lower depreciation, depletion and amortization (DD&A) expense, partially offset by higher lease operating expenses (LOE), other operating expense, exploration expenses, transportation, gathering and processing, severance and ad valorem taxes and income tax charges. See below for further details.
E&P crude oil price realizations averaged $94.89 per barrel in 2022 compared to $66.80 per barrel in 2021, an increase of 42% year over year. U.S. natural gas realized price per thousand cubic feet (MCF) averaged $6.68 in the current year compared to $3.71 per MCF in 2021, an increase of 80% year over year. Canada natural gas realized price per MCF averaged U.S. $2.76 in 2022compared to U.S. $2.43 per MCF in 2021, an increase of 14% year over year. E&P oil and natural gas LOE and severance and ad valorem taxes (production costs), on a per-unit basis, were $11.55 in 2022 (2021: $9.53). The increase in per-unit production costs in 2022 was primarily attributable to cost increases from inflationary pressures related to the onshore business and higher production from the Khaleesi and Mormont assets.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
United States E&P operations reported earnings of $1,521.9 million in 2022 compared to earnings of $766.3 million in 2021. Results were favorable $755.6 million in 2022 compared to the 2021 period driven by higher total revenues ($1,123.7 million), partially offset by higher LOE ($116.3 million), income tax expense ($186.9 million), other operating expense ($26.9 million), severance and ad valorem taxes ($16.1 million) and transportation, gathering and processing costs ($15.7 million).
Higher revenues are primarily attributable to higher realized prices in 2022 compared to 2021 and higher sales volumes (4,026 barrels of oil equivalent per day higher) which includes additional sales volumes from the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico. Higher LOE relates to higher production volumes, cost increases from inflationary pressures related to the onshore business and higher production handling fees at the Khaleesi and Mormont assets. Higher income tax expense is a result of higher pre-tax income. Increases in other operating expenses is primarily due to a higher asset retirement adjustments related to non-producing fields, ($37.2 million) and higher unfavorable mark to market revaluation on contingent consideration ($15.1 million) from prior Gulf of Mexico acquisitions. Higher severance and ad valorem taxes are due to higher revenues at Eagle Ford Shale and higher transportation, gathering and processing costs are due to higher sales volumes at the Gulf of Mexico.
Canadian E&P operations reported earnings of $134.2 million in 2022 compared to a loss of $16.1 million in 2021. Results were favorable $150.3 million compared to 2021 primarily due to higher revenue from production ($105.1 million), no impairment charges in 2022 (2021:$171.3 million) and lower DD&A ($22.3 million), partially offset by higher other operating expense ($78.6 million), higher income tax charges ($45.3 million), higher LOE ($18.8 million) and higher transportation, gathering and processing ($10.0 million).
Higher revenue is primarily attributable to higher realized prices and higher gas volumes (new wells added in 2022). Lower impairment and higher other operating expense in 2022 was the result of the 2021 impairment charge for Terra Nova. The impairment charge was recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment, which was later partially offset with a credit of $71.8 million in the third quarter of 2021 which was reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project and reversal of the asset abandonment decision. Higher income tax expense is a result of higher pre-tax income. Higher LOE is due to higher gas volumes and higher processing rates at Tupper Montney. Increased transportation, gathering and processing expense is due to higher sales volumes and an increase in transportation rates at Tupper Montney.
Other international E&P operations reported a loss from continuing operations of $77.0 million in 2022 compared to a loss of $33.5 million in 2021. Results were unfavorable $43.5 million in 2022 compared to 2021 and were largely driven by higher exploration expenses ($57.7 million) and higher income tax charges ($12.4 million), partially offset by lower impairment charges ($18.0 million) and higher revenues ($17.9 million). Exploration expenses in 2022 primarily relate to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil and the Tulum-1EXP exploration well in Block 5 in the Salina Basin offshore Mexico that failed to encounter commercial hydrocarbons.
2021 vs 2020
The results of operations in this section 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.
E&P from continuing operations recorded a earnings of $716.7 million in 2021 compared to a loss of $1,134.9 million in 2020. Results were favorable $1,851.6 million in 2021 compared to 2020 primarily due to higher oil, natural gas liquid and natural gas prices, significantly lower impairment charges, lower DD&A, lower LOE, lower exploration expenses and lower general and administrative (G&A) expenses, partially offset by higher transportation, gathering and processing and income tax charges. See below for further details.
Crude oil price realizations averaged $66.80 per barrel in 2021 compared to $38.02 per barrel in 2020, a price increase of 76% year over year. U.S. natural gas realized price per MCF averaged $3.71 in 2021 compared to $2.02 per MCF in 2020, an increase of 84% year over year. Canada natural gas realized price per MCF averaged U.S. $2.43 in 2021 compared to U.S. $1.79 per MCF in 2020, an increase of 36% year over year. Oil and natural gas production costs, on a per-unit basis, were $9.53 in 2021 (2020: $9.81). The decrease in per-unit production
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
costs in 2021 was primarily attributable to reduced costs associated with well workovers and concerted efficiency efforts.
United States E&P operations reported earnings of $766.3 million in 2021 compared to a loss of $1,014.3 million in 2020. Results were favorable $1,780.6 million in 2021 compared to the 2020 period primarily due to no impairment charges in 2021 (2020: $1,152.5 million), higher total revenues ($925.7 million), lower DD&A ($132.9 million) and lower LOE ($70.5 million), partially offset by higher income tax expense ($428.1 million) and higher other operating expense ($77.9 million). The impairment charge in 2020 was primarily the result of lower forecast future prices as of March 31, 2020, as a result of lower oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment.
Higher revenues were primarily due to higher realized prices (oil and condensate, natural gas and NGLs) year over year, partially offset by lower sales volume (7,514 barrels of oil equivalent per day lower) as a result of lower capital expenditures in 2020. Lower DD&A primarily resulted from the prior year impairment charge reducing the depreciable asset base. Lower LOE was primarily due to higher Gulf of Mexico workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). Higher income tax expense was a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE. Higher other operating expense was primarily due to an unfavorable mark-to-market revaluation on contingent consideration ($63.2 million; as a result of higher commodity prices) from prior Gulf of Mexico acquisitions.
Canadian E&P operations reported a loss of $16.1 million in 2021 compared to a loss of $35.0 million in 2020. Results were favorable $18.9 million compared to 2020 primarily due to higher revenue ($130.5 million) and lower DD&A ($49.4 million), partially offset by an impairment charge ($171.3 million), higher LOE ($14.7 million), transportation, gathering and processing ($15.8 million) and income tax charges ($19.7 million). 2021 results included an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project and reversal of the asset abandonment decision.
Higher revenue was primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower DD&A was primarily due to lower production volumes at Kaybob Duvernay following reduced capital expenditures throughout 2020. Higher LOE and transportation, gathering and processing costs were due to the cost of higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.
Other international E&P operations reported a loss from continuing operations of $33.5 million in 2021 compared to a loss of $85.6 million in 2020. Results were favorable $52.1 million in 2021 compared to 2020 primarily due to lower impairment charges ($21.7 million), lower income tax charges ($11.6 million), lower exploration expenses ($5.9 million) primarily in Brazil and Mexico and lower LOE ($4.8 million).
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.
(Dollars per equivalent barrel)
2022 2021 2020
Continuing operations
United States - Eagle Ford Shale
Lease operating expense $ 10.97 $ 8.96 $ 9.08
Severance and ad valorem taxes 4.27 2.91 2.06
DD&A expense 25.61 27.59 26.22
United States - Gulf of Mexico 1
Lease operating expense $ 13.19 $ 10.63 $ 11.95
Severance and ad valorem taxes 0.07 0.07 -
DD&A expense 10.12 9.51 13.48
Canada - Onshore
Lease operating expense $ 6.75 $ 6.20 $ 4.63
Severance and ad valorem taxes 0.06 0.09 0.07
DD&A expense 6.20 7.64 9.93
Canada - Offshore
Lease operating expense $ 14.20 $ 13.04 $ 17.86
DD&A expense 12.25 12.80 12.01
Total E&P continuing operations
Lease operating expense $ 10.65 $ 8.86 $ 9.34
Severance and ad valorem taxes 0.89 0.68 0.44
DD&A expense 12.18 13.05 15.36
Total oil and natural gas continuing operations -
excluding noncontrolling interest
Lease operating expense
$ 10.50 $ 8.65 $ 9.10
Severance and ad valorem taxes 0.93 0.71 0.47
DD&A expense 12.30 13.23 15.49
1 Includes results attributable to a noncontrolling interest in MP GOM.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Corporate
2022 vs 2021
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains and losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $438.3 million in 2022 compared to a loss of $668.0 million in 2021. The $229.7 million favorable variance is principally due to lower net losses on derivative instruments in 2022 compared to 2021 (2022: $320.4 million loss; 2021: $525.9 million loss), lower interest expense ($71.0 million) and higher foreign exchange gains ($26.0 million), partially offset by a lower tax benefit ($70.8 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling. As of December 31, 2022, the Company had no fixed price derivative swaps or collars contracts outstanding. Interest charges are lower in 2022 primarily due to lower overall debt and lower debt redemption costs ($8.3 million in 2022; $39.3 million in 2021) incurred by the Company. The Company reduced debt by $649.7 million in 2022. Lower income tax benefit is a result of lower pre-tax losses.
2021 vs 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains and losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $668.0 million in 2021 compared to a loss of $120.3 million in 2020. The $547.7 million unfavorable variance was principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $525.9 million loss; 2020: $202.7 million gain) and higher interest expense ($53.0 million), partially offset by a higher tax benefit ($148.3 million), lower restructuring charges ($48.8 million), lower G&A expenses ($12.9 million) and lower impairment charges ($7.1 million). Realized and unrealized losses on derivative instruments were due to an increase in market pricing in future periods whereby the swap contracts provided the Company with a fixed price and the collar contracts provided for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling. Higher interest costs were principally due to debt redemption costs on the 2022 notes and $550.0 million issuance of new notes in March 2021 that bear interest at a rate of 6.375% and mature on July 15, 2028. Higher income tax benefit was the result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges and G&A were due to the 2020 cost reduction efforts which included closing the Company’s previous 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.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Production Volumes and Prices
2022 vs 2021
Total hydrocarbon production from all E&P continuing operations averaged 175,156 barrels of oil equivalent per day in 2022, and represents a 5% increase from the 167,356 barrels per day produced in 2021. The increase is principally due to the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, new wells at Tupper Montney and lower weather related downtime in 2022.
Average crude oil and condensate production from continuing operations was 97,365 barrels per day in 2022 compared to 95,705 barrels per day in 2021. The increase of 1,660 barrels per day is principally due to increased production in the Gulf of Mexico (4,694 barrels per day) with new production from Khaleesi, Mormont, Samurai field development project, partially offset by normal declines at other fields in the Gulf of Mexico. Eagle Ford Shale production is lower (1,202 barrels per day) due to lower capital expenditures in 2020 and 2021, partially offset by new wells in 2022. Canada production is lower (2,260 barrels per day) due to normal field decline at Kaybob Duvernay and Hibernia, as well as a turnaround at Hibernia. On a worldwide basis, the Company’s crude oil and condensate prices average $94.89 per barrel in 2022 compared to $66.80 per barrel in the 2021 period, an increase of 42% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 10,681 barrels per day in 2022 compared to 10,385 barrels per day in 2021. The average sales price for U.S. NGL was $34.87 per barrel in 2022 compared to $27.97 per barrel in 2021. The average sales price for NGL in Canada was $55.65 per barrel in 2022 compared to $40.18 per barrel in 2021. 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 403 MMCFD in 2022 compared to 368 MMCFD in 2021. The increase of 35 MMCFD was primarily the result of higher volumes in Canada (32.4 MMCFD) and higher volumes in the Gulf of Mexico (2.1 MMCFD). The higher natural gas volumes in Canada was the result of new wells on production in 2022. Natural gas prices for the total Company averaged $3.66 per MCF in 2022, versus $2.74 per MCF average in the same period of 2021. Average realized natural gas prices in the U.S. and Canada in 2022 were $6.68 and $2.76 per MCF, respectively. Average realized natural gas prices in Canada are lower as a result of certain fixed price sales volume contracts.
2021 vs 2020
Total hydrocarbon production from all E&P continuing operations averaged 167,356 barrels of oil equivalent per day in 2021, which represented a 4% decrease from the 174,636 barrels per day produced in 2020.
Average crude oil and condensate production from continuing operations was 95,705 barrels per day in 2021 compared to 103,966 barrels per day in 2020. The decrease of 8,261 barrels per day was principally due to lower volumes in the Gulf of Mexico (2,703 barrels per day primarily due to reservoir decline), lower volumes at Kaybob Duvernay (2,272 barrels per day due to well decline) and lower Eagle Ford Shale production (765 barrels per day). On a worldwide basis, the Company’s crude oil and condensate prices averaged $66.80 per barrel in 2021 compared to $38.02 per barrel in 2020, an increase of 76% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 10,385 barrels per day in 2021 compared to 11,541 barrels per day in 2020. The average sales price for U.S. NGL was $27.97 per barrel in 2021 compared to $11.29 per barrel in 2020. The average sales price of NGL in Canada was $40.18 per barrel in 2021 compared to $18.54 per barrel in 2020. NGL prices were 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 368 MMCFD in 2021 compared to 355 MMCFD in 2020. The increase of 13 MMCFD was a primarily the result of higher volumes in Canada due to bringing online 14 new wells at Tupper Montney in 2021. Higher volumes at Tupper Montney were partially offset by lower natural gas volumes in the Gulf of Mexico.
Natural gas prices for the total Company averaged $2.74 per MCF in 2021, versus $1.85 per MCF average in 2020. Average realized natural gas prices in the U.S. and Canada in 2021 were $3.71 and $2.43 per MCF, respectively.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains hydrocarbons produced during the three years ended December 31, 2022.
(Barrels per day unless otherwise noted) 2022 2021 2020
Continuing operations
Net crude oil and condensate
United States Onshore 24,437 25,655 26,420
Gulf of Mexico 1
65,411 60,717 64,680
Canada Onshore 4,005 5,312 7,888
Offshore 2,812 3,765 4,893
Other 700 256 85
Total net crude oil and condensate - continuing operations 97,365 95,705 103,966
Net natural gas liquids
United States Onshore 5,181 5,092 5,248
Gulf of Mexico 1
4,597 4,176 4,978
Canada Onshore 903 1,117 1,315
Total net natural gas liquids - continuing operations 10,681 10,385 11,541
Net natural gas - thousands of cubic feet per day
United States Onshore 29,050 28,565 27,985
Gulf of Mexico 1
63,380 61,240 66,105
Canada Onshore 310,230 277,790 260,683
Total net natural gas - continuing operations 402,660 367,595 354,773
Total net hydrocarbons - continuing operations including NCI 2,3
175,156 167,356 174,636
Noncontrolling interest
Net crude oil and condensate - barrels per day (7,452) (8,623) (9,962)
Net natural gas liquids - barrels per day (280) (303) (416)
Net natural gas - thousands of cubic feet per day 2
(2,468) (3,236) (3,843)
Total noncontrolling interest (8,143) (9,465) (11,019)
Total net hydrocarbons produced - continuing and discontinued operations, excluding NCI 2,3
167,013 157,891 163,617
Estimated total proved net hydrocarbon reserves - million equivalent barrels 3,4
715.4 716.9 714.9
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, 2022, 2021 and 2020, include 18.2 MMBOE, 18.4 MMBOE and 17.4 MMBOE, respectively, relating to
noncontrolling interest.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains hydrocarbons sold during the three years ended December 31, 2022.
(Barrels per day unless otherwise noted) 2022 2021 2020
Continuing operations
Net crude oil and condensate
United States Onshore 24,437 25,655 26,420
Gulf of Mexico 1
64,840 60,544 65,621
Canada Onshore 4,005 5,312 7,888
Offshore 3,002 3,559 4,958
Other 663 195 78
Total net crude oil and condensate - continuing operations 96,947 95,265 104,965
Net natural gas liquids
United States Onshore 5,181 5,092 5,248
Gulf of Mexico 1
4,597 4,176 4,978
Canada Onshore 903 1,117 1,315
Total net natural gas liquids - continuing operations 10,681 10,385 11,541
Net natural gas - thousands of cubic feet per day
United States Onshore 29,050 28,565 27,985
Gulf of Mexico 1
63,380 61,240 66,105
Canada Onshore 310,230 277,790 260,683
Total net natural gas - continuing operations 402,660 367,595 354,773
Total net hydrocarbons - continuing operations including NCI 2,3
174,738 166,916 175,635
Noncontrolling interest
Net crude oil and condensate - barrels per day (7,369) (8,605) (10,127)
Net natural gas liquids - barrels per day (280) (303) (416)
Net natural gas - thousands of cubic feet per day 2
(2,468) (3,236) (3,843)
Total noncontrolling interest (8,060) (9,447) (11,184)
Total net hydrocarbons sold - continuing and discontinued operations, excluding NCI 2,3
166,678 157,469 164,451
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.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains the weighted average sales prices excluding transportation cost deduction for the three years ended December 31, 2022.
2022 2021 2020
(Weighted average Exploration and Production sales prices)
Continuing operations
Crude oil and condensate - dollars per barrel
United States Onshore $ 96.00 $ 66.90 $ 36.54
Gulf of Mexico 1
94.21 66.93 39.15
Canada 2
Onshore 89.88 61.79 32.42
Offshore 107.47 71.39 39.40
Other 94.37 69.21 63.51
Natural gas liquids - dollars per barrel
United States Onshore $ 33.85 $ 26.97 $ 11.67
Gulf of Mexico 1
36.01 29.14 10.84
Canada 2
Onshore 55.65 40.18 18.54
Natural gas - dollars per thousand cubic feet
United States Onshore $ 6.04 $ 3.83 $ 1.95
Gulf of Mexico 1
6.97 3.67 2.04
Canada 2
Onshore 2.76 2.43 1.79
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Financial Condition
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured revolving credit facility. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments and, as applicable, share repurchases. See below for additional discussion and analysis of the Company’s cash flows.
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $2,180.2 million in 2022 compared to $1,422.2 million in 2021. The increased cash provided by continuing operating activities of $758.0 million is primarily attributable to higher revenue from sales from production ($1,237.2 million), partially offset by higher LOE ($139.8 million), higher realized losses on derivative instruments ($121.5 million) and the change in receivable and payable working capital balances ($65.7 million). Higher revenues were primarily due to higher commodity prices driven by demand recovery from COVID-19 and geopolitical uncertainty and market disruption resulting from the Russia/Ukraine conflict.
Net cash provided by continuing operating activities was $619.5 million higher in 2021 than in 2020 due to higher revenue from sales from production ($1,049.5 million), the positive effect of movements on payable and receivable working capital balances ($118.5 million), lower lease operating expenses ($60.5 million) and lower general and administrative and cash restructuring expenses ($50.7 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $413.7 million; 2020: realized gain of $272.0 million). Higher revenues were primarily due to higher commodity prices driven by OPEC+ supply constraints and the increase in demand.
The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in Financing activities) during the three years ended December 31, 2022, 2021 and 2020 were $150.0 million, $165.7 million and $191.6 million, respectively. Lower cash interest paid in 2022 was primarily due to the early redemption of $649.7 million of the 2024 notes, 2025 notes, 2028 notes and the 2042 notes. Lower cash interest paid in 2021 was due to the repayment of the $200 million outstanding on the revolving credit facility, the early redemption of the 2022 notes and the early redemption of $300 million of the 2024 notes, partially offset by interest paid on the issuance of 2028 notes in the first quarter of 2021.
Cash Used for Investing Activities
Net cash required by investing activities were $1,109.5 million and $417.7 million in 2022 and 2021, respectively. In 2022, the Company acquired additional working interest in Kodiak (11.0%) and Lucius (3.4%) for $50.0 million and $78.5 million, respectively (also see Note D). Property additions and dry hole costs (excluding King’s Quay FPS), which include amounts expensed, were $985.5 million and $650.2 million in 2022 and 2021, respectively. In 2021, the Company received sales proceeds for the King’s Quay FPS of $267.7 million and also acquired additional interests in the proved property Lucius for $19.9 million. In 2020, cash used by investing activities included $113 million used to fund the development of the King’s Quay FPS.
The accrual (value of work done) basis capital expenditures were as follows:
Year Ended December 31,
(Millions of dollars) 2022 2021 2020
Capital Expenditures
Exploration and production $ 1,161.5 $ 690.1 $ 813.3
Corporate 21.7 21.1 13.3
Total capital expenditures 1,183.2 711.2 826.6
Total capital expenditures excluding proved property acquisitions 1,054.7 711.2 826.6
Total capital expenditures excluding proved property acquisitions and NCI $ 1,028.8 $ 688.2 $ 804.9
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Year Ended December 31,
(Millions of dollars) 2022 2021 2020
Property additions and dry hole costs per cash flow statements 1
$ 985.5 $ 650.2 $ 759.8
Property additions King's Quay FPS per cash flow statements - 17.7 113.0
Geophysical and other exploration expenses 30.6 26.9 32.3
Capital expenditure accrual changes and other 38.6 (3.9) (78.5)
Acquisition of oil properties per the cash flow statements 1
128.5 20.3 -
Total capital expenditures $ 1,183.2 $ 711.2 $ 826.6
1 Certain prior-period amounts have been reclassified to conform to the current period presentation.
Capital expenditures in the exploration and production business in 2022 compared to 2021 have increased and is primarily attributable to expenditures related to the Kodiak and Lucius acquisitions in the Gulf of Mexico ($128.5 million), Cutthroat-1 exploration well in Brazil ($38.4 million),Tulum-1EXP exploration well in Mexico ($21.6 million), higher capital invested at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico, higher development drilling activities in Eagle Ford Shale and Tupper Montney assets and higher expenditures related to the asset life extension at Terra Nova.
Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as result of capital expenditure reductions to support generating free cash flow.
Cash Used by and Provided by Financing Activities
Net cash required by financing activities was $1,081.6 million in 2022 compared to $794.5 million in 2021. In 2022, the cash required by financing activities was principally due to the early redemption of $647.7 million (excluding non cash gain of $2.0 million) of the 2024 notes, 2025 notes, 2028 notes and the 2042 notes, costs associated with early redemption ($8.3 million), distributions to noncontrolling interest ($183.0 million), dividends paid ($128.2 million) and payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million). The Company anticipates the final payments for the contingent consideration liability, related to the Gulf of Mexico acquisitions, to be paid in the first half of 2023. See Note P for further details.
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. As of December 31, 2022, the Company has a $800 million senior unsecured guaranteed credit facility (RCF) with a major banking consortium, which expires in November 2027. At December 31, 2022, the Company had no outstanding borrowings under the RCF and $57.6 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. If required, this provides the Company approximately $742 million availability on its RCF to fund investing activities from borrowings.
In 2021, the cash required by financing activities was principally due to the repayment of the balance outstanding on the revolving credit facility ($200.0 million), the early redemption of the remainder of the 2022 notes ($576.4 million), the early redemption of a portion of the 2024 notes ($300.0 million), costs associated with early redemption ($39.3 million), dividends paid ($77.2 million) and distributions to noncontrolling interest ($137.5 million), partially offset by issuance of 2028 notes ($541.9 million)
In 2020, net cash provided by financing activities of $39.7 million was principally from borrowings on the Company’s RCF ($200.0 million), partially offset by dividends paid ($96.0 million) and distributions to noncontrolling interest ($43.7 million).
Working Capital
At the end of 2022, working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) amounted to a net working capital liability of $285.5 million (2021: net working capital liability of $298.9 million). The total working capital liability decrease of $13.4 million in 2022 is primarily attributable to higher accounts receivable, net ($133.0 million) and lower accounts payable ($79.3 million), partially offset by higher other accrued liabilities ($82.7 million), higher operating lease liabilities ($81.0 million) and lower cash and cash equivalents ($29.2 million). Higher accounts receivable are principally due to higher
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
crude oil and natural gas pricing. Lower accounts payable is primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars) which matured at the end of 2022, partially offset by higher revenue payables principally due to higher crude oil and natural gas pricing and higher trades payable related to timing of Gulf of Mexico activities. Higher other accrued liabilities are associated with higher short-term contingent consideration obligations (from prior Gulf of Mexico acquisitions) due to a reclassification from long-term liabilities. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project.
Cash and cash equivalents as of December 31, 2022 totaled $492.0 million (2021: $521.2 million). There were no borrowings from the RCF outstanding at the end of the 2022 or 2021.
Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2022, cash and cash equivalents held outside the U.S. included U.S dollar equivalents of approximately $147.7 million (2021: $242.9 million), the majority of which was held in Canada ($83.3 million) and Mexico ($27.7 million). In addition, approximately $12.3 million and $6.1 million of cash was held in the U.K. and Brazil, respectively. 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 I for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.
Capital Employed
As of December 31, 2022, long-term debt of $1,822.4 million had decreased by $643.0 million compared to December 31, 2021, as a result the early redemption, in whole or in part, of the 2024 notes, 2025 notes, 2028 notes and the 2042 notes. The fixed-rate notes had a weighted average maturity of 7.7 years and a weighted average coupon of 6.2%.
A summary of capital employed as of December 31, 2022 and 2021 follows.
December 31, 2022 December 31, 2021
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 1,822.4 26.7 % $ 2,465.4 37.2 %
Murphy shareholders' equity 4,994.8 73.3 % 4,157.3 62.8 %
Total capital employed $ 6,817.2 100.0 % $ 6,622.7 100.0 %
Murphy shareholders’ equity was $4.99 billion at the end of 2022 (2021: $4.16 billion). Shareholders’ equity increased in 2022 primarily due to 2022 net income ($965.0 million) and a favorable revaluation of pension assets and liabilities ($99.4 million), partially offset by dividends paid ($128.2 million) and foreign currency translation losses, net of income taxes ($106.3 million). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 71 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 2022, compared to 2021 are discussed below.
Property, plant and equipment, net of depreciation increased $100.2 million principally due to capital expenditures in the year, partially offset by DD&A expense ($776.8 million) and foreign exchange rates applicable for our Canadian assets. Capital expenditures are discussed above in the ‘Cash Used for Investing Activities’ section.
Murphy had commitments for capital expenditures of approximately $282.4 million at December 31, 2022 (2021: $520.1 million). This amount includes $103.5 million for approved expenditure for capital projects relating to non-operated interests in deepwater U.S. Gulf of Mexico, principally at St. Malo ($98.9 million), non-operated Canada interests, mainly offshore ($33.3 million), non-operated Eagle Ford Shale ($13.3 million) and Brunei ($1.0 million).
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Operating lease assets increased $65.0 million principally due to additions for drilling rig lease extensions, partially offset by depreciation and a decrease related to changes in foreign exchange rates applicable for our Canadian assets.
Deferred Income tax assets decreased by $267.6 million as a result of the decrease in the U.S. net operating loss carryforward of $2.10 billion at year-end 2022, down from $2.75 billion at year-end 2021.
Deferred credits and other liabilities decreased $265.6 million primarily as a result reclassification of amounts to current, a favorable pension fair value remeasurement and cash pension contributions to the plan in 2022.
At December 31, 2022, the Company had no outstanding borrowings under the RCF and $57.6 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. Borrowings under the RCF are subject to certain interest rates, please refer to Note G for further details. At December 31, 2022, the interest rate in effect on borrowings under the facility would have been 6.96%. At December 31, 2022, the Company was in compliance with all covenants related to the RCF.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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.
The oil and 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 GHG 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 10.
Climate Change and Emissions
The world’s population and standard of living is growing steadily along with the demand for energy. Murphy recognizes that this may generate increasing amounts of GHG, which could 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 on 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 2022 Sustainability Report issued on August 4, 2022, which is not incorporated by reference hereto.
Other Matters
Impact of inflation - In 2022, many countries worldwide continued to experience a rise in inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021). In the U.S., inflation continued as a result of ongoing supply constraints and increasing demand of goods and services as countries continue their recovery from the COVID-19 pandemic. The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas industry and allied industries rather 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. Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.
As a result of increasing commodity prices for oil and natural gas, since the start of 2022, higher costs for goods and services in the oil and gas industry are being observed. Murphy has a dedicated procurement department focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
protected from the increasing price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher costs. Murphy continues to strive toward safely executing our work in an ever-increasing efficient manner to mitigate possible inflationary pressures in our business.
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 can be restricted to specific geographic areas. Natural gas demand is also impacted by demand driven by lower carbon emission and a view that natural gas is one option to transition from higher carbon emitting fuels.
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.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Critical Accounting Estimates - 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 110 to 119 of this Form 10-K report. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), 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, 2022 beginning on pages 4 and 110 of this Form 10-K report.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Property, Plant and Equipment - impairment of long-lived assets - The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its property, plant and equipment 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.
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.
There were no impairments recognized in 2022. In 2021, the Company recognized pretax noncash impairment charges of $196.3 million to reduce the carrying values at select properties. In 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans and $25.0 million for assets reported as Assets held for sale in the Consolidated Balance Sheets.
See also Note D 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 and 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 of December 31, 2022 the Company had a U.S. deferred tax asset associated with net operating losses of $442.7 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
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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 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 as of December 31, 2022, the Company has used a weighted average discount rate of 5.42% at year-end 2022 for the primary U.S. plans. This weighted average discount rate is 2.6% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 6.60% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2023 are expected to be $6.4 million higher than 2022 primarily due to the increase in the discount rate assumption for U.S. pension plan, which increases the amount of interest cost recognized in net periodic benefit expense. Cash contributions to all plans are anticipated to be $6.2 million lower in 2023.
In 2022, the Company paid $41.1 million into various retirement plans and $2.1 million into postretirement plans. In 2023, the Company is expecting to fund payments of approximately $32.2 million into various retirement plans and $4.8 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.
Recent Accounting Pronouncements
See Note B our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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 2022 under such contractual obligations and arrangements are shown in the table below. Amounts are undiscounted and therefore may differ to those presented in the financial statements.
(Millions of dollars) Amount of Obligations
Total 2023 2024 - 2025 2026 - 2027 After 2027
Debt, excluding interest $ 1,833.6 $ - $ 248.7 $ 543.2 $ 1,041.7
Operating leases and other leases ¹ 1,268.6 271.9 323.6 123.6 549.5
Capital expenditures, drilling rigs and other ² 1,230.5 552.3 245.9 151.2 281.1
Other long-term liabilities, including debt interest ³ 2,508.4 124.4 362.6 430.2 1,591.2
Total $ 6,841.1 $ 948.6 $ 1,180.8 $ 1,248.2 $ 3,463.5
1 Other leases refers to a finance lease in Brunei (see Note U to the financial statements).
2 Capital expenditures, drilling rigs and other includes $67.6 million, $33.3 million, $13.3 million and $1.1 million, in 2023 for approved capital projects in non-operated interests in U.S. Gulf of Mexico, Canada Offshore, U.S. Onshore and Other Foreign Offshore, respectively. Capital expenditures, drilling rigs and other includes $35.9 million in 2024 for approved capital projects in non-operated interests in U.S. Gulf of Mexico.
Also includes $66.5 million (2023), $105.5 million (2024 - 2025), $87.5 million (2026 - 2027) and $183.7 million (After 2027) for pipeline transportation commitments in Canada.
Also includes $5.0 million (2023), $9.8 million (2024 - 2025), $9.2 million (2026 - 2027) and $25.8 million (After 2027) 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 require 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 $232.4 million as of December 31, 2022.
Material off-balance sheet arrangements - Certain U.S. transportation contracts require minimum monthly payments through 2045, while onshore 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.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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 23, 2023, the NYMEX WTI forward curve price for the remainder of 2023 and 2024 were $75.05 and $71.85 per barrel, respectively; however we cannot predict what impact economic factors (including inflation, the Russia/Ukraine conflict and the COVID-19 pandemic) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash-flows.
The Company’s capital expenditure spend for 2023 is expected to be between $875 million and $1025 million, excluding the amount attributable to noncontrolling interest. Capital and other expenditures are routinely reviewed 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 2023 using operating cash flow and available cash. 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 under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company currently expects average daily production in 2023 to be between 182,700 and 190,700 barrels of oil equivalent per day (including noncontrolling interest of 7,200 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 plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation framework. Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note G).
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:
Volumes
(MMcf/d) Price/MCF Remaining Period
Area Commodity Type Start Date End Date
Canada Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023
Canada Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023
Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024
Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024
Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024
Forward-Looking Statements
This Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. 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, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG matters, or pay and/or increase dividends or make share repurchases and other capital allocation decisions, are all forward-
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, 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 15 of this Annual Report on Form 10-K. Murphy undertakes no duty to publicly update or revise any forward-looking statements, except as required by law.

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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 prices of crude oil, natural gas and petroleum products, foreign currency exchange rates and interest rates. As described in Note L, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were no outstanding crude oil derivative contracts as of December 31, 2022.
There were no derivative foreign exchange contracts in place as of December 31, 2022.
At December 31, 2022, long-term debt was $1,822.4 million. The fixed-rate notes have a weighted average coupon of 6.2%.

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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 63 through 127 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
PART II

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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, 2022, 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, 2022. 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, 2022 and their report is included on page 66 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 2022 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

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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 29 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 10, 2023 under the captions “Election of Directors” and “The Board and Committees.”
Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance 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 Corporate 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 10, 2023 under the captions “Compensation Discussion and Analysis” and “How Are We Compensated” 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 10, 2023 under the caption “Our Stockholders” and in the “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 10, 2023 under the caption “Election of Directors.”

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP, Houston, TX, Auditor Firm ID: 185.
Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 10, 2023 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 on Consolidated Financial Statements
(KPMG LLP , Houston, TX, Auditor Firm ID: 185)
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting (KPMG LLP, Houston, TX, Auditor Firm ID: 185)
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 - Property, Plant and Equipment
Note E - Assets Held for Sale and Discontinued Operations
Note F - Inventories
Note G - Financing Arrangements and Debt
Note H- Asset Retirement Obligations
Note I - Income Taxes
Note J - Incentive Plans
Note K - Employee and Retiree Benefit Plans
Note L - Financial Instruments and Risk Management
Note M - Earnings per Share
Note N - Other Financial Information
Note O - Accumulated Other Comprehensive Loss
Note P - Assets and Liabilities Measured at Fair Value
Note Q - Commitments
Note R - Environmental and Other Contingencies
Note S - Common Stock Issued and Outstanding
Note T - Business Segments
Note U - Leases
Note V - Restructuring Charges
Supplemental Oil and Natural Gas Information (unaudited)
Supplemental Quarterly Information (unaudited)
2. Financial Statement Schedules
Schedule II - Valuation Accounts and Reserves
PART IV
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 August 5, 2020
Exhibit 3.2 to Form 10-Q filed August 6, 2020
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 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
PART IV
4.10 Sixth Supplemental Indenture dated as of March 5, 2021, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, and Wells Fargo Bank, National Association as series trustee, relating to 6.375% Notes due 2028
Exhibit 4.2 to Form 8-K files March 5, 2021
*10.1 New Credit Agreement dated as of November 17, 2022 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
10.2 Murphy Oil Corporation Annual Incentive Plan
Exhibit 10.3 to Form 10-K filed on February 25, 2022
10.3 Murphy Oil Corporation 2012 Long-Term Incentive Plan
Exhibit A to definitive proxy statement filed March 29, 2012
10.4 Amendment to the Murphy Oil Corporation 2012 Long-Term Incentive Plan
Exhibit 10.8 to Form 10-K filed on February 27, 2020
10.5 Form of employee stock option (2012 Long-Term Incentive Plan)
Exhibit 99.1 to Form 10-K for the year ended December 31, 2013
10.6 Form of stock appreciation right (2012 Long-Term Incentive Plan)
Exhibit 99.3 to Form 10-Q filed May 7, 2014
10.7 Murphy Oil Corporation 2018 Long-Term Incentive Plan
Exhibit B to definitive proxy statement filed March 23, 2018
10.8 Amendment to the Murphy Oil Corporation 2018 Long-Term Incentive Plan
Exhibit 10.15 to Form 10-K filed on February 27, 2020
10.9 Form of employee performance-based restricted stock unit - stock settled grant agreement (2018 Long-Term Incentive Plan)
Exhibit 10.14 to Form 10-K for the year ended December 31, 2018
10.10 Form of employee performance-based restricted stock unit - stock settled grant agreement (2018 Long-Term Incentive Plan)
Exhibit 10.17 to Form 10-K filed on February 27, 2020
10.11 Form of employee time-based restricted stock unit - stock settled 3-year grant agreement (2018 Long-Term Incentive Plan)
Exhibit 10.15 to Form 10-K for the year ended December 31, 2018
10.12 Form of employee time-based restricted stock unit - stock settled 5-year grant agreement (2018 Long-Term Incentive Plan)
Exhibit 10.16 to Form 10-K for the year ended December 31, 2018
10.13 Murphy Oil Corporation 2020 Long-Term Incentive Plan
Exhibit A to definitive proxy statement filed March 30, 2020
10.14 Form of employee performance-based restricted stock unit - stock settled grant agreement (2020 LTI Plan)
Exhibit 10.21 to Form 10-K filed on February 26, 2021
10.15 Form of employee time-based restricted stock unit - stock settled 3-year grant agreement (2020 LTI Plan)
Exhibit 10.22 to Form 10-K filed on February 26, 2021
10.16 Form of employee time-based restricted stock unit - stock settled 5-year grant agreement (2020 LTI Plan)
Exhibit 10.23 to Form 10-K filed on February 26, 2021
10.17 Form of employee time-based restricted stock unit - cash settled 3-year grant agreement (2020 LTI Plan)
Exhibit 10.24 to Form 10-K filed on February 26, 2021
10.18 Form of employee time-based restricted stock unit - cash settled 5-year grant agreement (2020 LTI Plan)
Exhibit 10.25 to Form 10-K filed on February 26, 2021
10.19 Murphy Oil Corporation 2018 Stock Plan for Non-Employee Directors
Exhibit A to definitive proxy statement filed March 23, 2018
10.20 First Amendment to the 2018 Stock Plan for Non-Employee Directors
Exhibit 10.1 to Form 8-K filed April 25, 2018
10.21 Second Amendment to the 2018 Stock Plan for Non-Employee Directors
Exhibit 10.24 to Form 10-K filed on February 27, 2020
PART IV
10.22 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
10.23 Murphy Oil Corporation 2021 Stock Plan for Non-Employee Directors
Exhibit A to definitive proxy statement filed March 26, 2021
10.24 Form of non-employee director restricted stock unit award - stock settled grant agreement (2021 NED Plan)
Exhibit 10.27 to Form 10-Q filed on August 5, 2021
10.25 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
10.26 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
10.27 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
*10.28 First Amendment to the New Credit Agreement dated as of December 16, 2022 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
*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 Inline XBRL Instance Document
101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Labels Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
PART IV