EDGAR 10-K Filing

Company CIK: 717423
Filing Year: 2024
Filename: 717423_10-K_2024_0000717423-24-000008.json

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ITEM 1. BUSINESS
Item 1. BUSINESS
Summary
Murphy Oil Corporation is a global oil and 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. In 2013, the U.S. downstream business was separated from Murphy Oil Corporation’s oil and 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.
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 45, 74 through 76, 77 through 78, 98 through 100, and 103 through 118 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 2023, 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. and its subsidiaries and in Australia, Brazil, Brunei, Côte d’Ivoire, Mexico and Vietnam by wholly-owned Murphy Exploration & Production Company - International (Murphy Expro International) and its subsidiaries. Murphy’s operations and production in 2023 were in the United States, Canada and Brunei.
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 2023 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 192,640 barrels of oil equivalent per day, an increase of 10.0% compared to 2022.
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 2023 production and sales volume see pages 35 to 36.
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 108,084 barrels of crude oil and natural gas liquids per day and approximately 96 MMCF of natural gas per day in the U.S. in 2023. These amounts represented 94.0% of the Company’s total worldwide oil and natural gas liquids and 20.6% of worldwide natural gas production volumes.
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Item 1. Business - Continued
Offshore
The Company holds rights to approximately 600 thousand gross acres in the Gulf of Mexico. During 2023, approximately 73% of total U.S. hydrocarbon production was produced at fields in the Gulf of Mexico, of which approximately 90% was derived from ten fields, including St. Malo, Samurai, Khaleesi, Mormont, Cascade and Chinook, Kodiak, Lucius, Neidermeyer, Marmalard and Front Runner. Total average daily production in the Gulf of Mexico in 2023 was 79,397 barrels of crude oil and natural gas liquids and 70 MMCF of natural gas. At December 31, 2023, Murphy had total proved reserves for Gulf of Mexico fields of 132.3 million barrels of oil and natural gas liquids and 100.7 billion cubic feet of natural gas.
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 2023, approximately 27% of total U.S. hydrocarbon production was produced in the Eagle Ford Shale. Total 2023 production in the Eagle Ford Shale area was 28,641 barrels of oil and liquids per day and 25.7 MMCF per day of natural gas. At December 31, 2023, the Company’s proved reserves for the U.S. Onshore business totaled 130 million barrels of liquids and 192.4 billion cubic feet of natural gas.
Canada
In Canada, the Company holds working interests in Tupper Montney (100% owned), Kaybob Duvernay (operated) and two non-operated offshore assets - the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin. During 2023 the Company sold a portion of its working interest in Kaybob Duvernay and our entire 30% non-operated working interest in Placid Montney.
Onshore
Murphy has approximately 139 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 in Alberta. The Company has approximately 165 thousand gross acres of Kaybob Duvernay mineral rights. Daily production in 2023 in Onshore Canada averaged 3,618 barrels of liquids and 370 MMCF of natural gas, which included production from our divested Placid Montney of 274 barrels of liquids and 3 MMCF of natural gas. Total Onshore Canada proved liquids and natural gas reserves at December 31, 2023, were approximately 16.4 million barrels and 2.2 trillion cubic feet, respectively.
Offshore
The Company holds a non-operated interest in approximately 133 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 in Terra Nova.
Oil production in 2023 was 2,780 barrels of oil per day for Hibernia.
In 2023, the Terra Nova asset life extension project was completed and production restarted at the end of November. Production is expected to ramp up over the coming months. Total oil production in 2023 was 240 barrels of oil per day for Terra Nova.
Total proved reserves for offshore Canada at December 31, 2023 were approximately 22.3 million barrels of liquids and 14.8 billion cubic feet of natural gas.
Brazil
The Company holds a 20% non-operated working 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).
Murphy has a 100% working interest in three blocks in the Potiguar Basin (POT-M-857, POT-M-863 and POT-M-865).
Murphy’s total acreage position in Brazil as of December 31, 2023 is approximately 2.5 million gross acres, offsetting several major discoveries. There are no well commitments.
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Item 1. Business - Continued
Brunei
The Company has a working interest of 8.051% in Block CA-1 as of December 31, 2023.
Oil production in 2023 was 250 barrels of oil per day for Brunei.
Total proved reserves for our Jagus East discovery in Block CA-1 at December 31, 2023 were approximately 0.3 million barrels of liquids and 188 million cubic feet of natural gas. Block CA-1 covers 2 thousand gross acres.
Mexico
Murphy holds a 40% working interest and is the operator of Block 5 in the deepwater Salina Basin. The block covers approximately 623 thousand gross acres, with water depths ranging from 2,300 to 3,500 feet (700 to 1,100 meters). The license contract is currently in the first additional exploration period, which expires in May 2025 and has no outstanding commitments. In 2022, an exploration well was drilled and 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 in the Cuu Long Basin where the Declaration of Commerciality was made in January 2019, and the field Outline Development Plan was approved by Petrovietnam in August 2019. The Lac Da Trang (LDT) 1X exploration well, the last remaining commitment of the PSC, was completed in April 2019. In 2023, the Company received government approval of the field development plan and the Board of Directors of the Company (the Board) sanctioned the project. The Company anticipates drilling an exploration well in 2024.
In Block 15-2/17, the Company completed its seismic study program, which included 3D seismic reprocessing. In 2024 the Company anticipates drilling an exploration commitment well.
In blocks 144 and 145, the Company acquired 2D seismic in 2013 and undertook seabed surveys in 2015 and 2016. The Company will be seeking an extension to complete the remaining seismic commitment.
Total proved reserves for Vietnam at December 31, 2023 were approximately 12.1 million barrels of liquids and 2.8 billion cubic feet of natural gas.
Côte d’Ivoire
During the second quarter of 2023, Murphy signed PSCs as operator in five deepwater blocks in the Tano Basin offshore Côte d’Ivoire in Africa. The five blocks have a total area of 1.5 million gross acres, with Murphy initially holding a 90% working interest in four blocks and 85% working interest in the fifth block. Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire holds the remaining working interest for each block.
Commitments for the initial exploration periods across the five blocks consist of seismic reprocessing. Block CI-103 includes the Paon discovery, appraised with multiple wells by a previous operator. The PSC for this block also includes a commitment to submit a field development plan for this discovery by the end of 2025.
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Item 1. Business - Continued
Proved Reserves
Total proved reserves for crude oil, natural gas liquids and natural gas as of December 31, 2023 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 223.2 163.7 24.1 212.4
Onshore 109.4 70.3 16.3 136.7
Offshore 1
113.8 93.4 7.8 75.7
Canada 202.0 22.3 1.8 1,066.7
Onshore 183.4 6.0 1.8 1,053.0
Offshore 18.6 16.3 - 13.7
Other 0.3 0.3 - 0.2
Total proved developed reserves 425.5 186.3 25.9 1,279.3
Proved Undeveloped Reserves:
United States 87.9 64.3 10.2 80.7
Onshore 52.7 35.8 7.6 55.7
Offshore 2
35.2 28.5 2.6 25.0
Canada 213.5 13.1 1.5 1,193.4
Onshore 207.3 7.1 1.5 1,192.3
Offshore 6.2 6.0 - 1.1
Other 12.6 12.1 - 2.8
Total proved undeveloped reserves 314.0 89.5 11.7 1,276.9
Total proved reserves 3
739.5 275.8 37.6 2,556.2
1 Includes proved developed reserves of 12.8 MMBOE, consisting of 11.7 million barrels of oil (MMBBL) oil, 0.5 MMBBL NGLs and 3.8 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
2 Includes proved undeveloped reserves of 2.7 MMBOE, consisting of 2.3 MMBBL oil, 0.1 MMBBL NGLs and 1.5 BCF natural gas, attributable to the noncontrolling interest in MP GOM.
3 Includes proved reserves of 15.5 MMBOE, consisting of 14.0 MMBBL oil, 0.6 MMBBL NGLs and 5.3 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 71.3 BCF, 41.9 BCF and 2.8 BCF for the U.S. Canada and Other, respectively, with 1.2 BCF attributable to the noncontrolling interest in MP GOM.
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Item 1. Business - Continued
Murphy Oil’s 2023 total proved reserves and proved undeveloped reserves are reconciled from 2022 as presented in the table below:
(Millions of oil equivalent barrels) 1
Total
Proved
Reserves Total Proved
Undeveloped
Reserves
Beginning of year 715.4 279.4
Revisions of previous estimates (13.3) (3.7)
Extensions and discoveries 112.6 111.2
Improved recovery 0.4 0.4
Conversions to proved developed reserves - (73.3)
Sale of properties (5.2) -
Production (70.4) -
End of year 2
739.5 314.0
1 For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) of natural gas to one barrel of oil.
2 Includes 15.5 MMBOE and 2.7 MMBOE for total proved and proved undeveloped reserves, respectively, attributable to the noncontrolling interest in MP GOM.
During 2023, Murphy’s total proved reserves increased by 24.1 million barrels of oil equivalent (MMBOE). The increase in reserves principally relates to extensions of 86.4 MMBOE in Onshore Canada, 11.7 MMBOE in the Eagle Ford Shale, 12.6 MMBOE in Vietnam, 1.1 MMBOE in the Gulf of Mexico, and 0.9 MMBOE in Offshore Canada. These revisions were offset by production of 70.4 MMBOE in 2023, performance and price related reductions of 11.4 MMBOE in the Eagle Ford Shale and 1.9 MMBOE in the Gulf of Mexico, and disposition of 5.2 MMBOE in Onshore Canada.
Murphy’s total proved undeveloped reserves at December 31, 2023 increased 34.6 MMBOE from a year earlier. The proved undeveloped reserves reported in the table as extensions and discoveries during 2023 were predominantly attributable to four areas: the U.S. Gulf of Mexico, the Eagle Ford Shale in South Texas, Tupper Montney in Onshore Canada and Offshore Vietnam. The U.S. and Canadian assets had active development work ongoing during the year, while the Tupper Montney had increased capital allocations and the Lac Da Vang development project in Vietnam was sanctioned. The majority of proved undeveloped reserves associated with revisions of previous estimates was the result of performance adjustments in Tupper Montney and the Eagle Ford Shale and negative price revisions in the U.S. Onshore and U.S. Offshore fields, and were substantially offset by positive price revisions in Tupper Montney from decreased royalty rates and decelerated royalty incentive payouts arising from lower commodity prices. The majority of the proved undeveloped reserves migration to the proved developed category are attributable to drilling in Tupper Montney, the Gulf of Mexico, and the Eagle Ford Shale and the completion of the Terra Nova field life extension project in Offshore Canada. Other proved undeveloped increases resulted from sanctioned development plans for the Longclaw field in the Gulf of Mexico and Lac Da Vang field in Vietnam.
The Company spent approximately $704 million in 2023 to convert proved undeveloped reserves to proved developed reserves. In the next three years, the Company expects to spend a range of approximately $450 million to $700 million per year to move current undeveloped proved reserves to the developed category. The anticipated level of spending in 2024 primarily includes drilling and development in the Gulf of Mexico, Eagle Ford Shale, Tupper Montney and Vietnam areas.
At December 31, 2023, proved reserves are included for several development projects, including oil developments in the Eagle Ford Shale in South Texas, deepwater Gulf of Mexico, Kaybob Duvernay in Onshore Canada and Lac Da Vang in Vietnam; as well as natural gas developments in Tupper Montney in Onshore Canada. Total proved undeveloped reserves associated with various development projects at December 31, 2023 were approximately 314.0 MMBOE, which represents 42% 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 two undeveloped locations that exceed this five-year window. Total reserves associated with the two locations amount to less than 1% of the Company’s total proved reserves at year-end 2023. The development of certain reserves extends
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Item 1. Business - Continued
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
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X, which states that “proved oil and gas reserves are those quantities of oil and 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.” 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 gas reporting. Crude oil and condensate, natural gas liquids (NGL) and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators (“QREs”). QREs are technical professionals embedded within the asset teams. QRE qualification generally 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. Larger business units of the Company also employ Regional Reserves Coordinators who coordinate and provide oversight of the reserve submissions to senior management and the Corporate Reserves group. Murphy provides annual training to all Company reserves estimators to ensure SEC requirements associated with reserves estimation and Form 10-K reporting are fulfilled.
Proved reserves are 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 gas operational management and technical personnel. The Reserves General Manager joined Murphy in 2020 and has more than 32 years of industry experience. He has a Bachelor of Science in Mechanical Engineering and is 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 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. In 2023, third party audits were conducted for proved reserves covering 96.6% of total proved reserves. All audits conducted during this period were within the established +/- 10.0% tolerance.
Ryder Scott Company (“Ryder Scott”) performed audits for certain reserve estimates of Murphy’s U.S. fields as of December 31, 2023. The Ryder Scott summary report is filed as an exhibit to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 21 years of industry experience, joining Ryder Scott over 18 years ago. He is a registered Professional Engineer in the State of Texas.
McDaniel & Associates (“McDaniel”) performed audits for certain reserve estimates of our Canadian fields as of December 31, 2023. The McDaniel summary report is filed as an exhibit to this Annual Report on Form 10-K. The two technical advisors for McDaniel both have over 17 years of experience in the estimation and evaluation of reserves with McDaniel. Both are registered Professional Engineers with the Association of Professional Engineers and Geoscientists of Alberta.
Gaffney, Cline & Associates Pte Ltd (“GaffneyCline”) performed audits for certain reserve estimates of our Vietnam fields as of December 31, 2023. The GaffneyCline summary report is filed as an exhibit to this Annual Report on Form 10-K. The team lead for GaffneyCline has over 40 years of industry experience, joining GaffneyCline over 19 years ago.
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Item 1. Business - Continued
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 105 through 112 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, 2023 are shown on page 34 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 103 through 118 of this Form 10-K report.
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Item 1. Business - Continued
Acreage and Well Count
At December 31, 2023, 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 111 97 22 22 133 119
Gulf of Mexico 59 26 541 288 600 314
Total United States 170 123 563 310 733 433
Canada Onshore 129 105 175 138 304 243
Offshore 105 12 28 1 133 13
Total Canada 234 117 203 139 437 256
Mexico - - 623 249 623 249
Brazil - - 2,453 1,110 2,453 1,110
Brunei 2 - - - 2 -
Vietnam - - 7,324 4,571 7,324 4,571
Côte d’Ivoire - - 1,489 1,332 1,489 1,332
Totals 406 240 12,655 7,711 13,061 7,951
Certain acreage held by the Company will expire in the next three years.
Scheduled expirations in 2024 include 4,521 thousand net acres in Vietnam, 52 thousand net acres in in the Gulf of Mexico and 6 thousand net acres in Onshore Canada. Murphy has applied for and anticipates receiving lease extensions in Vietnam.
Acreage currently scheduled to expire in 2025 include 249 thousand net acres in Mexico, 75 thousand net acres in Brazil, 6 thousand net acres in the Gulf of Mexico and 1 thousand net acres in Onshore Canada.
Scheduled expirations in 2026 include 27 thousand net acres in the Gulf of Mexico and 6 thousand net acres in Offshore Canada.
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Item 1. Business - Continued
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, 2023.
Oil Wells Natural Gas Wells
Gross Net Gross Net
Country
United States Onshore 1,184 949 30 4
Gulf of Mexico 80 36 14 6
Total United States 1,264 985 44 10
Canada Onshore 20 14 342 326
Offshore 48 5 - -
Total Canada 68 19 342 326
Totals 1,332 1,004 386 336
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 - 1.3 - - - - - 1.3
Development 34.1 - 15.1 - - - 49.2 -
Exploration - - - - - 0.6 - 0.6
Development 29.1 - 22.1 - - - 51.2 -
Exploration - 0.1 - - - - - 0.1
Development 27.9 - 14.6 - - - 42.5 -
Murphy’s drilling wells in progress at December 31, 2023 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 - - 6.0 1.3 6.0 1.3
Gulf of Mexico 1.0 0.1 3.0 0.8 4.0 0.9
Canada Onshore - - 11.0 11.0 11.0 11.0
Offshore - - - - - -
Totals 1.0 0.1 20.0 13.1 21.0 13.2
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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 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. The Company has established a GHG emissions intensity reduction target of 15% to 20% by 2030 from our 2019 level, excluding our discontinued and divested Malaysia operations. In addition, we have endorsed the goal of eliminating routine flaring by 2030, under the current World Bank definition of routine flaring.
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 2023 Sustainability Report, located on the Company’s website, for details.
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 U.S. 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 with climate change. In addition, international climate efforts, including the 2015 “Paris Agreement” and the
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recent Conferences of the Parties of the UN Framework Convention on Climate Change (COP26, COP27, and COP28, 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 Canada, Murphy is subject to GHG regulations and resultant carbon pricing programs specific to the jurisdiction of operation. 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, 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.
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 Legislation, the provincially-administered Occupational Health and Safety Act (Alberta), the Workers Compensation Act (British Columbia) and the Workplace Hazardous Materials Information System.
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, Task Force on Climate-related Financial Disclosures (TCFD), Global Reporting Initiative, Ipieca and American Petroleum Institute.
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 2023, we published our fifth annual sustainability report, located on the Company’s website.
PART I
Item 1. Business - Continued
Human Capital Management
At Murphy, we believe in providing energy that empowers people, and that is what our 725 employees do every day. As of December 31, 2023, we had 438 office-based employees and 287 field employees, all of whom are guided by our mission, vision, values and behaviors. Together with the Executive Leadership Team, the Vice President, Human Resources and Administration, who reports directly to our 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 receives related updates from the Vice President, Human Resources and Administration on a regular basis including the review of compensation, benefits, succession and talent development, along with 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 and hiring acceptance rates against the market to ensure competitiveness 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 8, 2024.
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 that 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. Through our digital platform, My Murphy Learning, employees now have access to LinkedIn Learning with more than 15,000 courses, Continuing Education Unit (CEU) credit and certification opportunities, and access to expert instructors. We also administer mandatory compliance training for our employees through My Murphy Learning with a 100% utilization. Finally, 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.
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Item 1. Business - Continued
To enhance employees’ commitment to the Company’s Scorecard and understanding of annual incentive plans, three training courses were introduced covering the following topics: (1) Free Cash Flow and return metrics; (2) Lease Operating Expenses (LOE) and General and Administrative; and (3) Total Recordable Incident Rate, Spill Rate and Emissions. These training opportunities, in particular, enhanced the business acumen of our employee base, as well as brought renewed focus to how we measure success.
We strive to empower our leadership with programs that offer career advancement for experienced and emerging leaders. Over eighty managers participated in leadership programs, from a top rated business school, addressing focus areas such as strategic agility, enterprise thinking, building high-performing teams and enhancing trust.
We encourage employee engagement and solicit feedback through internal surveys and our employee-led 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 2023, our voluntary employee turnover rate was 6.0%.
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’s 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 Matching Gift Program, “Impact - Murphy Makes a Difference” Program or on their own and receive a Company match for donations.
Finally, we offer an Employee Assistance Program 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 receives DE&I updates on demographic data, strategic partnerships, recruiting strategies and programs from the Vice President, Human Resources and Administration on a regular cadence.
We seek input and program recommendations from our DE&I Committee 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 directors who are women, with at least one woman 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, 2023
Executive and Senior Level Managers 21 %
First- and Mid-Level Managers 22 %
Professionals 33 %
Other (Administrative Support and Field) 7 %
Total 22 %
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Item 1. Business - Continued
Minority 1 Representation (U.S.-Based Only)
December 31, 2023
Executive and Senior Level Managers 32 %
First- and Mid-Level Managers 28 %
Professionals 42 %
Other (Administrative Support and Field) 30 %
Total 35 %
1 As defined by the U.S. Equal Employment Opportunity Commission.
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.
Website Access to SEC Reports
Murphy Oil’s internet 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 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 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:
•worldwide and domestic supplies of, and demand for, crude oil, natural gas liquids and natural gas;
•the ability of the members of the Organization of the Petroleum Exporting Countries (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 gas producing regions, such as the Russia-Ukraine conflict and Israeli-Palestinian 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;
•the occurrence or threat of epidemics or pandemics, such as the outbreak of COVID-19, or any government response to such occurrence or threat which may lower the demand for hydrocarbon fuels;
•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 $77.62 per barrel in 2023, compared to $94.23 in 2022 and $67.91 in 2021. 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 $2.53 per million British Thermal Units (MMBTU) in 2023, compared to $6.38 in 2022 and $3.84 in 2021. The Company also has exposure to the Canadian benchmark natural gas price, Alberta Energy Company (AECO), which averaged C$2.64 per MCF in 2023, compared to C$5.31 in 2022 and C$3.63 in 2021. The Company has entered into certain forward fixed price contracts as detailed in the Outlook section beginning on page 51 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.
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.
•Lower oil and natural gas prices could lead to an inability to access, renew, or replace credit facilities, and could also impair access to other sources of funding as these mature, potentially negatively impacting our liquidity.
•Lower prices for oil and natural gas could cause the Company to lower its dividend because of lower cash flows.
See Note K 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 K for additional information on the derivative instruments used to manage certain risks related to commodity prices.
PART I
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 gas industry and experiences competition from other oil and gas companies, which include major integrated oil companies, independent producers of oil and 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 plans to continue assessing exploration activities as part of its overall strategy. In 2023, the Company participated in three exploration wells. The Longclaw #1 well (Green Canyon 433), located in the Gulf of Mexico, resulted in a commercial discovery while the Oso #1 (Atwater Valley 138) and Chinook #7 (Walker Ridge 425) wells, located in the Gulf of Mexico, failed to encounter commercial hydrocarbons. Additionally, the Company expensed previously suspended costs associated with the 2019 Cholula-1EXP well which was determined to be non-commercial. The Company has budgeted $120 million for its 2024 exploration program, which includes drilling two operated wells in Vietnam and two non-operated wells in the Gulf of Mexico.
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, and natural gas included in this report on pages 103 through 112 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 2023, 96.6% 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;
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Item 1A. Risk Factors - Continued
•Future reservoir performance which is materially different from models used to compute proved reserves; and
•Governmental regulations or actions which materially impact operations of a field.
The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2023, and including noncontrolling interests, approximately 32% of the Company’s crude oil and condensate proved reserves, 31% of natural gas liquids proved reserves and 50% 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 116 and 117 should not be considered as the market value of the reserves attributable to our properties. As required by U.S. 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 reliant on certain third party infrastructure to develop projects and operations.
The Company relies on the availability and capacity of infrastructure, such as transportation and processing facilities, and equipment that are often owned and operated by others. These third-party systems, facilities, and equipment may not always be available to the Company and, if available, may not be available at a price that is acceptable to the Company. The unavailability or high cost of such equipment or infrastructure could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our inability to access appropriate equipment and infrastructure in a timely manner and on acceptable terms may hinder our access to oil and natural gas markets or delay our oil and natural gas production.
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 2023, approximately 18% of the Company’s total production was at fields operated by others, while at December 31, 2023, approximately 13% of the Company’s total proved reserves were at fields operated by others.
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 prices, 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 operator’s or partners’ cash flows or ability to obtain adequate financing, or if an operator of our projects fails to adequately perform operations or fulfill its obligations under the applicable agreements, 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.
PART I
Item 1A. Risk Factors - Continued
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 a variety of locales, including urban, 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, tropical storms and extreme temperatures. 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, scientists have predicted that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that increase significant weather events, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If such effects were to occur, our operations could be adversely affected. Although the Company maintains insurance for such risks, due to policy deductibles and possible coverage limits, weather-related risks to our operations are not fully insured. For additional details on insurance, see Risk Factors, “General Risk Factors - 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.”
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, all of which may be exacerbated by climate change. 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.
Hydraulic fracturing operations subject the Company to operational risks inherent in the drilling and production of oil and natural gas.
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 risks associated with hydraulic fracturing operations include, but are not limited to, underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or groundwater contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or groundwater contamination resulting from hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses, and third-party claims alleging damages, which could adversely affect the Company’s financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water; the wastewater from oil and natural gas operations is often disposed of through underground injection. Certain increased seismic activities have been linked to underground water injection. Any diminished access to water for use in the hydraulic fracturing process, any inability to properly dispose of wastewater, or any further restrictions placed on wastewater, could curtail the Company’s operations due to regulatory initiatives or natural constraints such as drought or otherwise result in operational delays or increased costs.
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
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Item 1A. Risk Factors - Continued
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 methane and other GHG emissions; wildlife, habitat and water protection; water access, use and disposal; 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. For example, in December 2023, the U.S. EPA announced its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third-parties can monitor and report large methane emissions to the EPA. In addition, it is possible in the future, that 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 primarily uses hydraulic fracturing 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.
In addition, the U.S. Bureau of Ocean Energy Management (BOEM) and the U.S. Bureau of Safety and Environmental Enforcement (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 U.S. Outer Continental Shelf. 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
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Item 1A. Risk Factors - Continued
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.”
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, 2023, the Company had no outstanding borrowings under the RCF. See Note F 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.
Since 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 F for information regarding the Company’s outstanding debt as of December 31, 2023.
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 K 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 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 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 principal 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
•Counterparty credit risk related to forward price commodity hedge contracts to protect the Company’s cash flows against lower oil and natural gas prices
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.
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 or other 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 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 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 exceeding an average of $1 billion over three years 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
PART I
Item 1A. Risk Factors - Continued
may apply to us are generally effective in 2023 or later. 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 further changes may be enacted to U.S. and international tax rules and regulations, including the U.S. corporate tax system, which could have a material effect on our consolidated cash taxes in the future.
We may not be able to hire or retain qualified personnel to support our operations.
The success of our operations is dependent upon our ability to hire and retain qualified and experienced personnel. Changes 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 may make it more difficult for us to attract such qualified personnel. Additionally, the cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. If there is a decrease in the availability of qualified personnel, this may materially and adversely affect our results of operations, cash flows and financial condition.
Murphy’s sensitive information and operational technology systems and critical data 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 cyber infrastructure failure or a successfully executed, undetected cyber attack could significantly disrupt business operations. It might lead to downtime, revenue loss, and increased costs for remediation. Additionally, the compromise, theft, or unauthorized release of critical data could damage our reputation, weaken our competitive edge, and negatively impact our financial stability. Due to the nature of cyber-attacks, breaches to our systems could go undetected for a prolonged period of time.
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. In addition, laws and regulations governing, or proposed to govern, cybersecurity, data privacy and protection and the unauthorized disclosure of confidential or protected information, including legislation in domestic and international jurisdictions, pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
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 policy makers, regulators or other parties to delay or deny necessary licenses and permits to produce or transport crude oil and natural gas. 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. Following this notice, the Department of Interior has continued to approve permits, however, Murphy may experience delays in project approvals when the order is enforced. 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. The Company does not hold any onshore federal lands in the U.S.
PART I
Item 1A. Risk Factors - Continued
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. However, on December 14, 2023, the Secretary of the Interior approved the 2024-2029 National Outer Continental Shelf Oil and Gas Leasing Program, which contemplates only three potential oil and gas lease sales in the Gulf of Mexico through 2029. 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. Similar laws and regulations regarding climate change-related disclosures have been proposed or enacted in other jurisdictions, including California and the European Union. 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 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, 2023, 1.7% 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 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.
PART I
Item 1A. Risk Factors - Continued
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 subsequent 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. In November and December 2023, the international community gathered in Dubai at the 28th Conference to the Parties on the UN Framework Convention on Climate Change (COP28), during which multiple announcements were made, including a global agreement that calls for transitioning away from fossil fuels, and a pledge by about 50 oil and gas producing countries to achieve near-zero methane emissions by 2030. 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, COP28, 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 natural 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.
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.

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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 SEC as of December 31, 2023.
PART I

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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 103 to 118 and in Note D beginning on page 77.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. LEGAL PROCEEDINGS
Discussion of the Company’s legal proceedings are included in Note Q beginning on page 96.

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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, 2024 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.
Roger W. Jenkins - Age 62; Chief Executive Officer since 2013. Mr. Jenkins served as President from 2013 to 2024 and Chief Operating Officer from 2012 to 2013.
Eric M. Hambly - Age 49; President and Chief Operating Officer since February 2024. Mr. Hambly served as Executive Vice President, Operations from 2020 to 2023. He also 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.
Thomas J. Mireles - Age 51; 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.
E. Ted Botner - Age 59; Executive Vice President, General Counsel and Corporate Secretary since February 2024. Mr. Botner served as Senior Vice President, General Counsel and Corporate Secretary from 2020 to 2023. He also served as Vice President, Law and Corporate Secretary from 2015 to 2020 and Manager, Law and Corporate Secretary from 2013 to 2015.
Daniel R. Hanchera - Age 66; Senior Vice President, Business Development since 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 55; 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 47; Vice President, Corporate Planning and Treasurer since 2022. Mr. Jumawan was Assistant Treasurer from 2017 to 2022.
Maria A. Martinez - Age 49; 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 50; Vice President, Sustainability since 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 58; Vice President, Tax since 2018.
Paul D. Vaughan - Age 57, Vice President and Controller since 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 58; 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 1,974 stockholders of record as of December 31, 2023. Information on dividends per share by quarter for 2023 and 2022 are reported on page 119 of this Form 10-K report.
Issuer Purchase of Equity Securities:
The following table summarizes repurchases of our common stock occurring in the fourth quarter 2023.
Period Total Number of Shares Purchased Average Price Paid Per Share 1
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs2,3
(in thousands)
October 1 through October 31, 2023 - $ - - $ 525,000
November 1 through November 30, 2023 1,154,348 $ 43.29 1,154,348 $ 475,000
December 1 through December 31, 2023 572,288 $ 43.66 572,288 $ 450,000
1 Amounts exclude 1% excise tax and fees on share repurchases.
2 In August 2022, the Board authorized an initial share repurchase program of up to $300 million of the Company’s common stock. On October 30, 2023, the Company authorized an increase to the share repurchase program by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million. Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion.
3 Maximum approximate dollar values reported represent amounts at end of the month. During 2023, the Company repurchased 3,411,158 shares of its common stock under the share repurchase program in open-market transactions for $150.0 million, excluding taxes and fees.
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, 2018 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. Our peer group for 2023 is presented in the table below. Callon Petroleum Company, Matador Resources Company and SM Energy Company were added to Murphy’s peer group in 2023 and CNX Resources Corporation was removed. 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 Kosmos Energy Ltd. Range Resources Corporation
Callon Petroleum Company
Marathon Oil Corporation SM Energy Company
Coterra Energy Inc. Matador Resources Company
Southwestern Energy Company
Devon Energy Corporation Ovintiv Inc. Talos Energy Inc.
Hess Corporation PDC Energy Inc. 1
2018 2019 2020 2021 2022 2023
Murphy Oil Corporation 100 119 56 125 210 214
Peer Group 100 108 74 147 233 220
S&P 500 Index 100 131 156 200 164 207
XOP Index 100 112 72 135 215 215
1 PDC Energy Inc. was acquired in 2023 and therefore has been excluded from the above table and graph of cumulative total return.
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
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the consolidated financial statements and accompanying notes to consolidated financial statements, which are included in Item 8 of this Annual Report on Form 10-K. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See Forward-Looking Statements at the end of this section and Risk Factors under Item 1A. Discussion and analysis of 2021 results and year-over-year comparisons between 2022 and 2021 are not included in this Form 10-K and can be found in Item 7 of the 2022 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.
Murphy Oil Corporation is a worldwide oil and gas exploration and production company with both onshore and offshore operations and properties. 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. A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.
The analysis and discussion in this section includes amounts attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
Significant Company financial and operational highlights during 2023 were as follows:
•Generated net income of $661.6 million and net cash provided by operating activities of $1,748.8 million;
•Produced 193 thousand barrels of oil equivalent (BOE) per day (186 thousand excluding noncontrolling interest, NCI);
•Sanctioned the Lac Da Vang field development project in Vietnam;
•Enhanced exploration portfolio with signing production sharing contracts for five blocks in Côte d’Ivoire;
•Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico;
•Acquired an 8% working interest in the non-operated Zephyrus discovery in the Gulf of Mexico for a purchase price of approximately $13 million, net of closing adjustments;
•Resumed operations at non-operated Terra Nova field in offshore Canada during the fourth quarter of 2023, with production ramping up through first quarter 2024;
•Advances made under the capital allocation framework1:
◦Early debt retirement of approximately $500 million, a 27% debt reduction in the year
◦Repurchased shares of common stock under the share repurchase program for $150 million, excluding excise taxes, commissions and fees
◦Increased cash dividends by 10% since the fourth quarter of 2022 to $0.275 per share, or $1.10 per share annualized
•Achieved 134% (139% excluding NCI) total proved reserve replacement with year-end proved reserves of 739.5 million barrels of oil equivalent (724.0 million excluding NCI).
1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022. On October 30, 2023, the initial share repurchase program of $300 million of the Company’s common stock was increased by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids, 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 natural gas liquids. 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 capital borrowing from lending institutions and note holders.
For the year ended December 31, 2023, the Company’s net income from continuing operations was $725.2 million, a decrease of $415.6 million compared to 2022. Lower net income from continuing operations was largely driven by lower revenues and other income ($472.5 million), higher lease operating expenses ($105.1 million) and higher exploration expenses ($101.6 million), partially offset by lower other operating expense ($91.0 million) and lower income tax expense ($113.5 million). Lower revenues and other income resulted from overall lower pricing partially offset by overall higher sales volumes and lower losses on derivative instruments. Higher lease operating expenses were related to higher sales volumes as well as additional costs for workover and maintenance activities at Gulf of Mexico operations. Higher exploration costs were the result of dry hole expense for the Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells, that did not find commercial hydrocarbons in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire, and the expensing of previously suspended exploration costs for the Cholula-1EXP well in Mexico. No losses were recorded in 2023 on derivative instruments as no fixed price derivative swaps or collar contracts were in effect during the period. Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico. Lower income tax expense was the result of lower pre-tax income.
For the year ended December 31, 2023, total hydrocarbon production was 192,640 barrels of oil equivalent per day, an increase of 10% compared to 2022. The increase was principally due to new well production volumes in the Gulf of Mexico from the Khaleesi, Mormont, Samurai field development project, new well production from Tupper Montney and lower royalty rates, partially offset by lower production volumes at other fields in the Gulf of Mexico due to additional downtime.
Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below.
(Millions of dollars)
2023 2022 2021
Exploration and production
United States $ 905.1 $ 1,521.9 $ 766.3
Canada 41.6 134.2 (16.1)
Other International (65.5) (77.0) (33.5)
Total exploration and production
881.2 1,579.1 716.7
Corporate and other (156.0) (438.3) (668.0)
Income from continuing operations
725.2 1,140.8 48.7
Loss from discontinued operations 1
(1.5) (2.1) (1.2)
Net income including noncontrolling interest
723.7 1,138.7 47.5
Net income attributable to noncontrolling interest
62.1 173.7 121.2
Net income attributable to Murphy
$ 661.6 $ 965.0 $ (73.7)
1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
E&P Continuing Operations: 2023 vs 2022
The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.
Please also refer to Schedule 6 - Results of Operations for Oil and Natural Gas Producing Activities in the Supplemental Oil and Natural Gas Information section for additional supporting tables.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following are summarized income statements for E&P continuing operations.
(Millions of dollars) 2023 2022 2021
Revenues and other income
Revenue from production
$ 3,376.6 $ 4,038.5 $ 2,801.2
Sales of purchased natural gas
72.2 181.7 -
Other income
8.0 26.7 17.5
Total revenues and other income
3,456.8 4,246.9 2,818.7
Cost and Expenses
Lease operating expenses 784.4 679.3 539.5
Severance and ad valorem taxes 42.8 57.0 41.2
Transportation, gathering and processing 233.0 212.7 187.0
Costs of purchased natural gas 51.7 172.0 -
Depreciation, depletion and amortization 850.5 763.9 782.1
Impairments of assets - - 189.3
Accretion of asset retirement obligations 46.0 46.2 46.6
Total exploration expenses 234.8 133.1 69.0
Selling and general expenses 37.7 44.5 43.6
Other 56.9 141.8 31.0
Results of operations before taxes 1,119.0 1,996.4 889.4
Income tax provisions
237.8 417.3 172.7
Results of operations (excluding Corporate segment) 1
$ 881.2 $ 1,579.1 $ 716.7
1 Includes results attributable to a noncontrolling interest in MP GOM.
Pricing
The following table contains the weighted average sales prices for the three years ended December 31, 2023.
(Weighted average sales prices)
2023 2022 2021
Crude oil and condensate - dollars per barrel
United States - Onshore $ 76.96 $ 96.00 $ 66.90
United States - Offshore 1
77.38 94.21 66.93
Canada - Onshore 2
72.84 89.88 61.79
Canada - Offshore 2
84.20 107.47 71.39
Other 2
86.60 94.37 69.21
Natural gas liquids - dollars per barrel
United States - Onshore $ 19.69 $ 33.85 $ 26.97
United States - Offshore 1
21.94 36.01 29.14
Canada - Onshore 2
35.87 55.65 40.18
Natural gas - dollars per thousand cubic feet
United States - Onshore $ 2.26 $ 6.04 $ 3.83
United States - Offshore 1
2.78 6.97 3.67
Canada - Onshore 2
2.06 2.76 2.43
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2023.
(Average price for the period) 2023 2022 2021
Oil and NGLs
WTI ($/BBL) $ 77.62 $ 94.23 $ 67.91
Natural gas
NYMEX ($/MMBTU) 2.53 6.38 3.84
AECO (C$/MCF) 2.64 5.31 3.63
Production Volumes
The following table contains hydrocarbons produced during the three years ended December 31, 2023. For further discussion on volumes, please see Revenues from Production section on page 37.
(Barrels per day unless otherwise noted) 2023 2022 2021
Net crude oil and condensate
United States - Onshore
24,070 24,437 25,655
United States - Offshore 1
73,473 65,411 60,717
Canada - Onshore
2,937 4,005 5,312
Canada - Offshore
3,020 2,812 3,765
Other 250 700 256
Total net crude oil and condensate
103,750 97,365 95,705
Net natural gas liquids
United States - Onshore
4,617 5,181 5,092
United States - Offshore 1
5,924 4,597 4,176
Canada - Onshore
681 903 1,117
Total net natural gas liquids
11,222 10,681 10,385
Net natural gas - thousands of cubic feet per day
United States - Onshore
25,863 29,050 28,565
United States - Offshore 1
70,239 63,380 61,240
Canada - Onshore
369,906 310,230 277,790
Total net natural gas
466,008 402,660 367,595
Total net hydrocarbons - including NCI 2,3
192,640 175,156 167,356
Noncontrolling interest
Net crude oil and condensate - barrels per day (6,210) (7,452) (8,623)
Net natural gas liquids - barrels per day (220) (280) (303)
Net natural gas - thousands of cubic feet per day (2,089) (2,468) (3,236)
Total noncontrolling interest 2,3
(6,778) (8,143) (9,465)
Total net hydrocarbons - excluding NCI 2,3
185,862 167,013 157,891
Estimated total proved net hydrocarbon reserves
- million equivalent barrels 3,4
739.5 715.4 716.9
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, 2023, 2022 and 2021, include 15.5 MMBOE, 18.2 MMBOE and 18.4 MMBOE, respectively, relating to
noncontrolling interest.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Sales Volumes
The following table contains hydrocarbons sold during the three years ended December 31, 2023. For further discussion on volumes, please see Revenues from Production section on page 37.
(Barrels per day unless otherwise noted) 2023 2022 2021
Net crude oil and condensate
United States - Onshore
24,070 24,437 25,655
United States - Offshore 1
73,373 64,840 60,544
Canada - Onshore
2,937 4,005 5,312
Canada - Offshore
2,559 3,002 3,559
Other 349 663 195
Total net crude oil and condensate
103,288 96,947 95,265
Net natural gas liquids
United States - Onshore
4,617 5,181 5,092
United States - Offshore 1
5,924 4,597 4,176
Canada - Onshore
681 903 1,117
Total net natural gas liquids
11,222 10,681 10,385
Net natural gas - thousands of cubic feet per day
United States - Onshore
25,863 29,050 28,565
United States - Offshore 1
70,239 63,380 61,240
Canada - Onshore
369,906 310,230 277,790
Total net natural gas
466,008 402,660 367,595
Total net hydrocarbons - including NCI 2,3
192,178 174,738 166,916
Noncontrolling interest
Net crude oil and condensate - barrels per day (6,200) (7,369) (8,605)
Net natural gas liquids - barrels per day (220) (280) (303)
Net natural gas - thousands of cubic feet per day (2,089) (2,468) (3,236)
Total noncontrolling interest 2,3
(6,768) (8,060) (9,447)
Total net hydrocarbons - excluding NCI 2,3
185,410 166,678 157,469
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
Revenues from Production
The Company’s production revenues by country and product were as follows:
(Millions of dollars) 2023 2022 2021
Revenues from production
United States - Oil $ 2,748.5 $ 3,085.9 $ 2,105.2
United States - Natural gas liquids 80.6 124.4 94.6
United States - Natural gas
92.7 225.3 121.7
Canada - Oil 156.7 249.2 212.5
Canada - Natural gas liquids 8.9 18.3 16.4
Canada - Natural Gas
278.2 312.6 245.9
Other - Oil
11.0 22.8 4.9
Total revenues from production
$ 3,376.6 $ 4,038.5 $ 2,801.2
Revenues from production in 2023 decreased by $661.9 million compared to 2022. Lower revenues from U.S. E&P was primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher overall sales volumes from the Gulf of Mexico. Higher sales volumes were driven by new well performance from the Khaleesi, Mormont, Samurai field development project, and were partially offset by lower sales volumes at other fields. Lower revenues from Canadian E&P was primarily attributable to lower realized prices and lower sales volumes at Kaybob Duvernay partially offset by higher sales volumes at Tupper Montney. Lower sales volumes at Kaybob Duvernay were primarily due to the divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, as well as natural declines. Higher sales volumes at Tupper Montney were the result of new wells coming online in 2023, improved well performance, and lower royalty rates.
Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. Sales of purchase natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 34.
Other Income
Other income was $8.0 million in 2023, a decrease of $18.7 million compared to 2022. Lower other income was primarily the result of a gain on sale of the Thunder Hawk field in the third quarter of 2022.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Lease Operating and Transportation, Gathering and Processing Expenses
The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:
(Millions of dollars) (Dollars per equivalent barrel)
2023 2022 2021 2023 2022 2021
Lease operating expenses
United States - Onshore
$ 150.3 $ 137.6 $ 115.7 $ 12.48 $ 10.94 $ 8.93
United States - Offshore
480.4 385.1 290.7 14.46 13.19 10.63
Canada - Onshore 140.3 139.5 119.4 5.89 6.75 6.20
Canada - Offshore 11.5 15.6 16.9 12.30 14.20 13.04
Other 1.9 1.5 (3.2) 14.94 6.25 (44.94)
Total lease operating expenses $ 784.4 $ 679.3 $ 539.5 $ 11.18 $ 10.65 $ 8.86
Transportation, gathering and processing
United States - Onshore
$ 12.7 $ 18.4 $ 26.1 $ 1.05 $ 1.47 $ 2.02
United States - Offshore
144.3 123.8 100.4 4.34 4.24 3.67
Canada - Onshore 72.2 65.3 57.4 3.03 3.16 2.98
Canada - Offshore 3.8 5.2 3.1 4.12 4.76 2.36
Total transportation, gathering and processing $ 233.0 $ 212.7 $ 187.0 $ 3.32 $ 3.34 $ 3.07
Lease operating expenses and transportation, gathering and processing expenses in 2023 increased by $105.1 million and $20.3 million, respectively, compared to 2022. Higher lease operating expenses and increased transportation, gathering and processing expenses from U.S. E&P were primarily due to increased sales volumes and higher operating expenses for additional workover and maintenance activities from the Gulf of Mexico operations.
Depreciation, Depletion and Amortization Expense
The Company’s depreciation, depletion and amortization expense by geographic area were as follows:
(Millions of dollars) (Dollars per equivalent barrel)
2023 2022 2021 2023 2022 2021
Depreciation, depletion and amortization expense
United States - Onshore
$ 316.7 $ 321.4 $ 356.4 $ 26.29 $ 25.55 $ 27.50
United States - Offshore
389.3 295.6 260.1 11.72 10.12 9.51
Canada - Onshore 133.4 128.1 147.2 5.60 6.20 7.64
Canada - Offshore 8.8 13.4 16.6 9.47 12.25 12.80
Other 2.3 5.4 1.8 18.05 22.19 26.78
Total depreciation, depletion and amortization expense
$ 850.5 $ 763.9 $ 782.1 $ 12.12 $ 11.98 $ 12.84
Depreciation, depletion and amortization expense (DD&A) in 2023 increased by $86.6 million compared to 2022. Higher DD&A was primarily the result of higher sales volumes and higher rates from the Gulf of Mexico. DD&A from Canadian E&P increased at Tupper Montney due to higher sales volumes and higher rates, substantially offset by lower sales volumes and lower rates at Kaybob Duvernay.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Exploration Expenses
The Company’s exploration expenses were as follows:
(Millions of dollars) 2023 2022 2021
Exploration expenses
Dry holes and previously suspended exploration costs $ 169.8 $ 82.1 $ 17.3
Geological and geophysical 26.1 10.4 11.8
Other exploration 28.0 27.3 21.0
Undeveloped lease amortization 10.9 13.3 18.9
Total exploration expenses
$ 234.8 $ 133.1 $ 69.0
Exploration expenses in 2023 increased by $101.7 million compared to 2022. Higher dry holes and previously suspended exploration costs primarily relate to the dry hole expense of Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells in the Gulf of Mexico, which encountered non-commercial hydrocarbons, and the write-off of previously suspended exploration costs for the Cholula-1EXP well in Mexico. Higher geological and geophysical expenses in 2023 relate to the purchased seismic data for Côte d’Ivoire. In 2022, dry holes and previously suspended exploration costs primarily relate to expensed costs for the Cutthroat-1 exploration well in block SEAL-M-428 in offshore Brazil and the Tulum-1EXP exploration well in Block 5 in offshore Mexico that did not encounter commercial hydrocarbons.
Other Expenses
Other expenses were $56.9 million in 2023, a decrease of $84.9 million compared to 2022. Other expenses were lower primarily due to a lower unfavorable contingent consideration adjustment of $7.1 million in 2023 (2022: $78.3 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note O). In addition, there were lower asset retirement adjustments related to non-producing fields of $18.2 million in 2023 (2022: $35.0 million).
Income Taxes
Income taxes were $237.8 million in 2023, a decrease of $179.5 million compared to 2022. Lower income taxes were primarily the result of lower pre-tax income (see Note H).
Corporate: 2023 vs 2022
Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to E&P. Realized and unrealized losses on derivative instruments would result from increases in market oil prices relating to 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.
Corporate activities reported a loss of $156.0 million in 2023, a favorable variance of $282.2 million compared to 2022. The favorable variance was primarily due to no current period losses on derivative instruments in 2023, compared to a loss for the same period in 2022 ($320.4 million) and lower interest expense ($38.6 million), partially offset by lower income tax benefits ($66.0 million) and foreign exchange loss of $10.7 million in 2023 compared to foreign exchange gain of $23.0 million in 2022. Interest charges are lower in 2023 primarily due to lower overall debt levels as the Company reduced debt by $498.2 million and $647.7 million during 2023 and 2022, respectively. During 2023 and as of December 31, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding. Lower income tax benefit was a result of lower pre-tax losses.
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 RCF. 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.
Cash Flows
The following table presents the Company’s cash flows for the periods presented.
(Millions of dollars) 2023 2022 2021
Net cash provided by (required by):
Net cash provided by continuing operations activities $ 1,748.8 $ 2,180.2 $ 1,422.2
Net cash required by investing activities
(998.7) (1,109.4) (417.7)
Net cash required by financing activities
(923.7) (1,081.6) (794.5)
Net cash required by discontinued operations
- (14.5) -
Effect of exchange rate changes on cash and cash equivalents (1.2) (3.9) 0.6
Net (decrease) increase in cash and cash equivalents
$ (174.8) $ (29.2) $ 210.6
Cash Provided by Continuing Operations Activities
Net cash provided by continuing operations activities in 2023 was $431.4 million lower compared to 2022. The decrease was primarily attributable to lower revenue from production ($661.9 million), higher payments of contingent consideration related to prior Gulf of Mexico acquisitions ($139.6 million), higher lease operating expenses ($105.1 million) and timing of working capital settlements ($33.6 million), partially offset by lower realized losses on derivative instruments ($535.2 million). Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities. During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions. See Note O for further details.
The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in “Financing Activities”) during the two years ended December 31, 2023, and 2022 were $108.9 million and $150.0 million, respectively. Lower cash interest paid in 2023 was primarily due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.050% senior notes due 2029 (2029 Notes) in the aggregate amount of $498.2 million.
Cash Required by Investing Activities
Net cash required by investing activities in 2023 was $110.7 million lower compared to 2022. The decrease was primarily due to the proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million) and lower acquisition capital ($93.0 million), partially offset by higher property additions and dry hole costs ($80.6 million).
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Year Ended December 31,
(Millions of dollars) 2023 2022 2021
Property additions and dry hole costs per cash flow statements 1
$ 1,066.0 $ 985.5 $ 650.2
Geophysical and other exploration expenses 46.0 30.6 26.9
Acquisition of oil properties per the cash flow statements 1
35.6 128.5 20.3
Capital expenditure accrual changes and other (9.5) 38.6 (3.9)
Property additions King's Quay Floating Production System (FPS) per cash flow statements
- - 17.7
Total capital expenditures $ 1,138.1 $ 1,183.2 $ 711.2
1 Certain prior-period amounts have been reclassified to conform to the current period presentation.
Total accrual basis capital expenditures are shown below.
Year Ended December 31,
(Millions of dollars) 2023 2022 2021
Capital Expenditures
Exploration and production $ 1,114.0 $ 1,161.5 $ 690.1
Corporate 24.1 21.7 21.1
Total capital expenditures 1,138.1 1,183.2 711.2
Total capital expenditures excluding proved property acquisitions 1,111.0 1,054.7 711.2
Total capital expenditures excluding proved property acquisitions and NCI $ 1,040.8 $ 1,028.8 $ 688.2
Lower capital expenditures in 2023 compared to 2022 were primarily attributable to lower development expenditures at the Khaleesi, Mormont, Samurai field development project, lower spend at the Kodiak and Lucius fields and lower acquisition capital, partially offset by higher exploratory drilling and higher development expenditures at the Dalmatian and St. Malo fields. Capital expenditures in 2023 primarily relate to development drilling and field development activities in the Eagle Ford Shale ($361.5 million); development activities in the Gulf of Mexico, primarily related to St. Malo, Dalmatian, Samurai and Marmalard fields ($310.1 million); development drilling and field development activities at the Tupper Montney field ($142.0 million); field development at Terra Nova for the asset life extension project ($44.7 million); and total exploration costs of $214.3 million. Exploration costs were primarily for activities at Chinook #7 (Walker Ridge 425), Oso #1 (Atwater Valley 138) and Longclaw #1 (Green Canyon 433) within the Gulf of Mexico and activities at Côte d’Ivoire. Costs of $169.8 million primarily associated with Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) were expensed to dry hole costs in 2023 as the Company determined there were non-commercial hydrocarbons present.
Cash Required by Financing Activities
Net cash required by financing activities in 2023 decreased by $157.9 million compared to 2022. In 2023, cash used in financing activities was principally for the redemption of the remaining $248.7 million principal outstanding on its 2025 Notes and the tendering of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes. In addition, the Company repurchased common shares ($150.0 million, excluding accrued excise tax), paid contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the ‘Cash Provided by Continuing Operating Activities’ section, paid cash dividends to shareholders of $1.10 per share ($171.0 million), and distributed funds to the noncontrolling interest in the Gulf of Mexico ($29.4 million).
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Liquidity
At December 31, 2023, the Company had approximately $1.1 billion of liquidity consisting of $317.1 million in cash and cash equivalents and $796.2 million available on its committed senior unsecured RCF with a major banking consortium.
The Company’s $800 million senior unsecured RCF expires in November 2027 and as of December 31, 2023, the Company had no outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF. Borrowings under the RCF are subject to certain interest rates, please refer to Note F for further details. At December 31, 2023, the interest rate in effect on borrowings under the facility would have been 7.70%. At December 31, 2023, the Company was in compliance with all covenants related to the RCF.
Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2023, cash and cash equivalents held outside the U.S. included U.S dollar equivalents of approximately $148.9 million (2022: $147.7 million), the majority of which was held in Canada ($105.2 million) and Mexico ($18.1 million). In addition, approximately $9.6 million and $8.3 million of cash was held in the U.K. and Spain, 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 H for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.
Working Capital
(Millions of dollars) December 31, 2023 December 31, 2022
Working capital
Total current assets $ 752.2 $ 972.3
Total current liabilities 846.5 1,257.8
Net working capital liability
$ (94.3) $ (285.5)
As of December 31, 2023, net working capital had a favorable increase of $191.2 million compared to December 31, 2022. The favorable increase was primarily attributable to lower other accrued liabilities ($302.8 million) and lower accounts payable ($96.9 million), partially offset by lower accounts receivable ($47.2 million) and a lower cash balance ($174.9 million). Lower accrued liabilities were primarily due to payments made for contingent consideration obligations from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made in 2023. Lower accounts payable were primarily due to decreases in unrealized losses on derivative instruments (commodity price swaps and collars), decreases in royalties payable due to lower revenues, payments made for abandonment activities and drilling and completions activities. Lower unrealized losses on derivative instruments were as a result of no commodity derivative instrument contracts entered into or outstanding during 2023. Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas liquids and lower pricing received for all crude oil, natural gas liquids and natural gas.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Capital Employed
A summary of capital employed as of December 31, 2023 and 2022 follows.
December 31, 2023 December 31, 2022
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 1,328.4 19.9 % $ 1,822.4 26.7 %
Murphy shareholders' equity 5,362.8 80.1 % 4,994.8 73.3 %
Total capital employed $ 6,691.2 100.0 % $ 6,817.2 100.0 %
As of December 31, 2023, long-term debt decreased by $494.0 million compared to December 31, 2022, as a result of the redemption and early redemption of, in whole or in part, the 2025 Notes, 2027 Notes, 2028 Notes, and 2029 Notes. The fixed-rate notes had a weighted average maturity of 8.1 years and a weighted average coupon of 6.2%.
Murphy’s shareholders’ equity increased by $368.0 million in 2023 primarily due to net income earned ($661.6 million), partially offset by cash dividends paid ($171.0 million) and shares repurchased ($150.0 million, including excise tax). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 69 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 2023, compared to 2022 are discussed below.
Property, plant and equipment, net of depreciation, decreased $2.8 million principally due to DD&A expense ($861.6 million) and divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, substantially offset by capital expenditures in the year and foreign exchange rates applicable for the Canadian assets. Capital expenditures are discussed above in the ‘Cash Required for Investing Activities’ section.
Murphy had commitments for capital expenditures of approximately $209.8 million at December 31, 2023 (2022: $282.4 million). This amount includes $75.1 million for approved expenditures for capital projects relating to non-operated interests in deepwater U.S. Gulf of Mexico, principally at St. Malo ($61.7 million), non-operated Canada interests, mainly offshore ($11.6 million), non-operated Lucius ($13.3 million) and non-operated Eagle Ford Shale ($11.8 million).
Operating lease assets decreased $201.2 million principally due to depreciation on these assets.
Deferred Income tax assets decreased by $117.5 million as a result of the decrease in the U.S. net operating loss carryforward from $2.1 billion at year-end 2022 to $1.7 billion at year-end 2023.
Long term asset retirement obligations increased $86.8 million primarily due to accretion and additions and revisions related to Gulf of Mexico and Eagle Ford Shale operations.
Non-current operating lease liabilities decreased $190.8 million primarily due to 2023 annual payments reducing operating lease liabilities for drilling rig and vessel commitments.
Deferred income tax liabilities increased $61.7 million due to capital related tax deductions.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Other Key Performance Metrics
The Company uses other operational performance and income metrics to review operational performance. Management uses adjusted net income, EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income also excludes certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA and 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 GAAP.
The following table reconciles reported net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
Year Ended December 31,
(Millions of dollars)
2023 2022 2021
Net income attributable to Murphy (GAAP) 1
$ 661.6 $ 965.0 $ (73.7)
Discontinued operations loss 1.5 2.1 1.2
Net income from continuing operations attributable to Murphy
663.1 967.1 (72.5)
Adjustments 2:
Write-off of previously suspended exploration wells 17.1 22.7 -
Asset retirement obligation losses (gains) 16.9 30.8 (71.8)
Foreign exchange loss (gain)
10.9 (23.0) (1.0)
Mark-to-market loss on contingent consideration
7.1 78.3 63.2
Mark-to-market (gain) loss on derivative instruments
- (214.7) 112.1
(Gain) on sale of assets - (14.5) -
Early redemption of debt cost - 10.3 43.9
Impairment of assets - - 196.3
Tax benefits on investments in foreign areas - - (8.9)
Charges related to Kings Quay transaction - - 4.9
Unutilized rig charges - - 8.7
Total adjustments, before taxes
52.0 (110.1) 347.4
Income tax (benefit) expense related to adjustments (6.4) 23.8 (75.2)
Total adjustments after taxes 45.6 (86.3) 272.2
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 708.7 $ 880.8 $ 199.7
Net income from continuing operations per average diluted share (GAAP)
$ 4.23 $ 6.14 $ (0.47)
Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 4.52 $ 5.59 $ 1.29
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
2 Certain prior-period amounts have been reclassified to conform to the current period presentation.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.
Year Ended December 31,
(Millions of dollars)
2023 2022 2021
Net (loss) income attributable to Murphy (GAAP) 1
$ 661.6 $ 965.0 $ (73.7)
Income tax expense 195.9 309.5 (5.9)
Interest expense, net 112.4 150.8 221.8
Depreciation, depletion and amortization expense 2
836.7 748.2 760.6
EBITDA attributable to Murphy (Non-GAAP) 1,806.6 2,173.5 902.8
Accretion of asset retirement obligations 2
41.0 40.9 41.1
Write-off of previously suspended exploration well 17.1 22.7 -
Asset retirement obligation loss (gain)
16.9 30.8 (71.8)
Foreign exchange loss (gain)
10.8 (23.0) (1.0)
Mark-to-market loss gain on contingent consideration
7.1 78.3 63.2
Mark-to-market (gain) loss on derivative instruments
- (214.7) 112.1
Discontinued operations loss
1.5 2.1 1.2
Gain on sale of assets 2
- (14.5) -
Impairment of assets 2
- - 196.3
Unutilized rig charges - - 8.7
Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,901.0 $ 2,096.1 $ 1,252.6
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
2 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 noncontrolling interest.
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, Environment and Corporate Responsibility Committee consisting of certain members of the Board.
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 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 2023 Sustainability Report issued on August 2, 2023, which is not incorporated by reference hereto.
Other Matters
Impact of inflation - In 2023, 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 for 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.
To combat impacts of inflation and/or supply and demand factors, Murphy has dedicated personnel in marketing and procurement departments, 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 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
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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 emissions 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.
Critical Accounting Estimates - In preparing the Company’s consolidated financial statements in accordance with 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 prices 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 103 to 112 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
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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, 2023 beginning on pages 4 and 103 of this Form 10-K report.
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 ensure 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 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 2023 or 2022.
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.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
As of December 31, 2023 the Company had a U.S. deferred tax asset associated with net operating losses of $357.5 million. In reviewing the likelihood of realizing this asset, the Company considered the reversal of taxable temporary differences, carryforward periods and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur. Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil and condensate, NGLs and natural gas, (b) estimated reserves for crude oil and condensate, NGLs and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.
Accounting for retirement and postretirement benefit plans - Murphy and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of 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, 2023, the Company has used a weighted average discount rate of 5.15% at year-end 2023 for the primary U.S. plans. This weighted average discount rate is 0.3% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 8.00% 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 2024 are expected to be $0.7 million higher than in 2023 primarily due to the increase in the benefit obligations at December 31, 2023 compared to the prior year, which increases the interest cost recognized in net periodic benefit costs. Cash contributions to all plans are anticipated to be $2.9 million higher in 2024.
In 2023, the Company paid $37.5 million into various retirement plans and $2.0 million into postretirement plans. In 2024, the Company is expecting to fund payments of approximately $38.0 million into various retirement plans and $4.4 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 in 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 2023 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 2024 2025 - 2026 2027 - 2028 After 2028
Debt, excluding interest $ 1,334.9 $ - $ - $ 815.4 $ 519.5
Operating leases and other leases ¹ 1,019.3 245.7 148.4 125.4 499.8
Capital expenditures, drilling rigs and other ² 1,289.6 434.4 264.2 197.9 393.1
Other long-term liabilities, including debt interest ³ 2,379.0 98.9 197.6 139.4 1,943.1
Total $ 6,022.8 $ 779.0 $ 610.2 $ 1,278.1 $ 3,355.5
1 Other leases refers to a finance lease in Brunei (see Note T).
2 Capital expenditures, drilling rigs and other includes $51.6 million, $11.8 million, $11.6 million and $4.0 million, in 2024 for approved capital projects in non-operated interests in U.S. Gulf of Mexico, U.S. Onshore, Canada Offshore and Other Foreign Offshore, respectively. Capital expenditures, drilling rigs and other includes $23.5 million in 2025 for approved capital projects in non-operated interests in U.S. Gulf of Mexico.
Also includes $74.6 million (2024), $145.3 million (2025 - 2026), $140.2 million (2027 - 2028) and $308.1 million (After 2028) for pipeline transportation commitments in Canada.
Also includes $4.1 million (2024), $7.7 million (2025 - 2026), $7.7 million (2027 - 2028) and $22.5 million (After 2028) for long term take or pay commitments relating to natural 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 $200.6 million as of December 31, 2023.
Material off-balance sheet arrangements - Certain U.S. transportation contracts require minimum monthly payments through 2045, while Onshore Canada transportation and processing contracts call for minimum monthly payments through 2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above.
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Outlook
The oil and gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the Results of Operations section discussing revenues, on page 37, lower average crude oil price during in 2023 directly impacted the Company’s product sales revenue.
As of close on February 21, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:
2024 2025
WTI ($/BBL)
75.63 70.84
NYMEX ($/MMBTU)
2.41 3.38
AECO (US$ Equivalent/MCF)
1.39 2.38
In 2023, liquids from continuing operations represented approximately 60% of total hydrocarbons produced on an energy equivalent basis. In 2024, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%. If the prices for crude oil and natural gas are lower in 2024 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.
The Company currently expects average daily production in 2024 to be between 187,100 and 195,100 barrels of oil equivalent per day (including noncontrolling interest of 7,100 BOEPD). If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.
Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.
We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) 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 2024 is expected to be between $920 million and $1,020 million, excluding 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 2024 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 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 designed to allow for additional shareholder returns and debt reduction. 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. During 2023, the Board authorized a $300 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $600 million. As of December 31, 2023, the Company has $450 million remaining available to repurchase.
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 F).
PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
As of February 21, 2024, the Company has entered into 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 162 C$2.39 1/1/2024 12/31/2024
Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2024 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 (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-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; geopolitical concerns; 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, banking system or economies in general, including inflation. 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. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
PART II

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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 K, Murphy periodically 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, 2023.
There were no derivative foreign exchange contracts in place as of December 31, 2023.
At December 31, 2023, long-term debt was $1,328.4 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 65 through 120 of this Form 10-K report.
PART II

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

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board.
Based on their evaluation, with the participation of the Company’s management, as of December 31, 2023, 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, 2023. 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, 2023 and their report is included on page 64 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 2023 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
During the three months ended December 31, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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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 8, 2024 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 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 8, 2024 under the captions “Compensation Discussion and Analysis” and “How We Are Compensated” and in various compensation schedules.
As required by U.S federal securities laws, the Company revised its incentive-based compensation recoupment (clawback) policy providing for the recovery of erroneously awarded incentive-based compensation received by current or former executive officers. We have filed our written recoupment policy as Exhibit 10.29 to this Form 10-K report and as of December 31, 2023, there have been no accounting restatements requiring compensation recoupment.

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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 8, 2024 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 8, 2024 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 8, 2024 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 - Inventories
Note F - Financing Arrangements and Debt
Note G - Asset Retirement Obligations
Note H - Income Taxes
Note I - Incentive Plans
Note J - Employee and Retiree Benefit Plans
Note K - Financial Instruments and Risk Management
Note L - Earnings per Share
Note M - Other Financial Information
Note N - Accumulated Other Comprehensive Loss
Note O - Assets and Liabilities Measured at Fair Value
Note P - Commitments
Note Q - Environmental and Other Contingencies
Note R - Common Stock Issued and Outstanding
Note S - Business Segments
Note T - Leases
Supplemental Oil and Natural Gas Information (unaudited)
Supplemental Quarterly Information (unaudited)
2. Financial Statement Schedules
Schedule II - Valuation Accounts and Reserves
All other financial statement schedules are omitted because either they are not applicable, or the required information is included in the consolidated financial statements or notes thereto.
PART IV
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 filed February 27, 2019
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 filed February 28, 2011
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 filed March 16, 2005
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 filed March 16, 2005
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 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
4.5 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
4.6 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
4.7 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
4.8 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
Exhibit 4.9 to Form 10-K filed February 27, 2020
4.9 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 filed 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
Exhibit 10.1 to Form 10-K filed February 27, 2023
PART IV
10.2 Murphy Oil Corporation Annual Incentive Plan
Exhibit 10.3 to Form 10-K filed 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 February 27, 2020
10.5 Form of employee stock option (2012 Long-Term Incentive Plan)
Exhibit 99.1 to Form 10-K filed February 28, 2014
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 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 filed February 27, 2019
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 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 filed February 27, 2019
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 filed February 27, 2019
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 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 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 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 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 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 February 27, 2020
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 filed February 27, 2019
10.23 Form of non-employee director restricted stock unit award - stock settled grant agreement (2018 NED Plan)
Exhibit 10.26 to Form 10-K filed February 27, 2020
10.24 Murphy Oil Corporation 2021 Stock Plan for Non-Employee Directors
Exhibit A to definitive proxy statement filed March 26, 2021
10.25 Form of non-employee director restricted stock unit award - stock settled grant agreement (2021 NED Plan)
Exhibit 10.27 to Form 10-Q filed August 5, 2021
10.26 Murphy Oil Corporation Non-Qualified Deferred Compensation Plan for Non-Employee Directors
Exhibit 10.6 to Form 10-K filed February 26, 2016
PART IV
10.27 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
10.28 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
Exhibit 10.28 to Form 10-K filed February 27, 2023
*10.29
Murphy Oil Corporation Compensation Recoupment Policy
*10.30
Form of employee performance-based restricted stock unit (2020 LTI Plan)
*10.31
Form of employee time-based restricted stock unit - A (2020 LTI Plan)
*10.32
Form of employee time-based restricted stock unit - B (2020 LTI Plan)
*10.33
Form of employee time-based restricted stock unit - C (2020 LTI Plan)
*10.34
Form of employee time-based restricted stock unit - D (2020 LTI Plan)
*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.
*23.4
Consent of Gaffney, Cline & Associates Pte. 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 U.S. Onshore and Gulf of Mexico
*99.2 Ryder Scott reserves audit report for MP GOM JV
*99.3 McDaniel independent audit report for Canada Onshore proved crude oil and natural gas reserves
*99.4
Gaffney, Cline independent audit report for Vietnam 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