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美国
证券交易委员会
华盛顿特区20549
表格 10-Q  
(Mark One)
☒根据1934年证券交易法第13或15(d)节的季度报告
截至季度结束日期的财务报告September 30, 2024
或者
☐根据1934年证券交易法第13或15(d)节的转型报告书
过渡期从              to
佣金文件号 1-8590
murphyoilcorplogo.jpg
墨菲石油公司
(根据其章程规定的注册人准确名称)
特拉华州71-0361522
（设立或组织的其他管辖区域）（联邦纳税人识别号）
9805 Katy Fwy， G-200号套房77024
休斯顿，得克萨斯州(邮政编码)
，（主要行政办公地址）
(281)675-9000
(注册人电话号码，包括区号)
在法案第12(b)条的规定下注册的证券：
各等级的头衔交易代码在其上注册的交易所的名称
普通股，面值1.00美元墨菲石油请使用moomoo账号登录查看New York Stock Exchange
请用勾号表示，申报人（1）在过去12个月内（或申报人需要提交此类报告的更短期间内）已提交1934年证券交易法第13或15（d）条规定的所有报告，并且（2）在过去90天中一直受到这些申报要求的约束。☒Yes☐ 否
请用勾号表示，申报人在过去的12个月（或者要求提交此类文件的较短期间）内是否已按照S-t法规第405条要求提交了每个交互式数据文件。 ☒Yes☐ 否
请用复选标记指示注册者是大型加速执笔人，加速执笔人、非加速执笔人、较小报告公司还是新兴成长公司。请参阅《交易所法》第120亿.2条中“大型加速执笔人”、“加速执笔人”、“较小报告公司”和“新兴成长公司”的定义。
大型加速报告人☒加速文件申报人☐未加速的报告人☐更小的报告公司☐新兴成长公司☐
如果是一家新兴成长公司，请选择该注册人是否选择不使用根据交易所法案第13(a)条规定提供的任何新的或修改后的财务会计准则的延长过渡期的复选标记。☐
请用勾选标记表示注册者是否属于空壳公司（如《法案》第120亿.2规定）。 ☐ 是 ☒ 否
2024年10月31日尚有待结算的普通股数量为1.00美元。 145,843,359.


墨菲石油公司
目录
              操作
1
目录
第一部分 - 财务信息
项目 1. 基本报表
墨菲石油公司及其子公司
汇编表格
(未经审计)

（金额以千美元计，股份数量除外）9月30日,
2024		12月31日,
2023
资产
流动资产
现金及现金等价物$271,223 $317,074 
应收账款净额
263,110 343,992 
存货51,048 54,454 
预付费用44,234 36,674 
总流动资产629,615 752,194 
资产、厂房及设备的账面价值，减去累计折旧、减值和摊销，为13,758,462的。13,135,385在2023年被Men's Journal评为美国排名第一的健身房连锁店
8,189,942 8,225,197 
营业租赁资产859,706 745,185 
延迟所得税– 435 
待摊费用和其他资产37,156 43,686 
资产总额$9,716,419 $9,766,697 
负债和股东权益
流动负债
长期债务的流动部分，融资租赁$748 $723 
应付账款429,832 446,891 
应付所得税21,778 21,007 
其他应付税款34,321 29,339 
经营租赁负债253,336 207,840 
其他应计负债144,818 140,745 
流动负债合计884,833 846,545 
长期负债，包括融资租赁义务1,279,324 1,328,352 
资产养老责任929,965 904,051 
递延贷款及其他负债278,831 309,605 
非流动经营租赁负债620,058 551,845 
延迟所得税318,233 276,646 
负债合计$4,311,244 $4,217,044 
股权
累积优先股，面值$100，已授权400,000股，无已发行股数
$– $– 
普通股，面值$1.00，已授权 450,000,000发行股份195,100,6282024年股份总数为43,795,955股和195,100,6282023年的股份
195,101 195,101 
超过面值的资本835,655 880,297 
保留盈余6,766,706 6,546,079 
累计其他综合损失(552,707)(521,117)
自家保管的股票(1,995,018)(1,737,566)
墨菲股东权益5,249,737 5,362,794 
非控股权益155,438 186,859 
股东权益总计5,405,175 5,549,653 
负债和所有者权益总额$9,716,419 $9,766,697 

查看基本报表附注，第 7.
2
目录
墨菲石油公司及其子公司
营业收入综合表
(未经审计)
三个月结束
9月30日,		九个月结束
9月30日,
(单位：千美元，除每股数据外)2024202320242023
营业收入及其他收入
生产营业收入$753,169 $945,889 $2,345,282 $2,541,956 
销售购买的天然气– 7,877 3,742 64,628 
客户销售总收入753,169 953,766 2,349,024 2,606,584 
衍生工具损失(1,344)– (1,344)– 
资产出售收益和其他收入6,506 5,879 9,834 9,365 
总收入和其他收入758,331 959,645 2,357,514 2,615,949 
费用和支出
租赁营业费用222,886 193,402 716,778 587,678 
遣散费和按比例计算的税10,503 10,937 31,006 35,142 
运输、集输和加工47,438 61,518 157,461 175,308 
购买天然气成本– 5,467 3,147 47,393 
勘探费用，包括未开发租赁摊销31,284 26,514 118,390 152,489 
销售和一般性费用24,871 30,745 78,925 74,398 
折旧、减值和摊销223,632 237,493 650,309 648,830 
资产养老负债增值13,241 11,675 39,068 34,196 
其他营业费用5,450 4,385 10,497 21,333 
资产减值– – 34,528 – 
总成本和费用579,305 582,136 1,840,109 1,776,767 
持续经营业务的营业收入179,026 377,509 517,405 839,182 
其他收入（损失）
其他收益（损失）(3,926)8,811 33,870 1,044 
利息费用，净额(21,258)(29,984)(62,265)(88,695)
总其他损失(25,184)(21,173)(28,395)(87,651)
未来营业收入净额153,842 356,336 489,010 751,531 
所得税费用2,122 78,111 64,855 166,813 
持续经营业务收入151,720 278,225 424,155 584,718 
终止经营的损失，净(608)(421)(2,123)(744)
净利润包括非控股权益151,112 277,804 422,032 583,974 
扣除非控制权益所得的净利润12,018 22,462 65,197 38,701 
净利润归属于墨菲$139,094 $255,342 $356,835 $545,273 
普通股基本每股收益（损失）
持续经营业务$0.93 $1.64 $2.37 $3.50 
已停止运营的业务– – (0.01)– 
净利润$0.93 $1.64 $2.36 $3.50 
每股收益（亏损）-摊薄
持续经营业务$0.93 $1.63 $2.35 $3.47 
已停止运营的业务– – (0.01)– 
净利润$0.93 $1.63 $2.34 $3.47 
每股普通股派息$0.300 $0.275 $0.900 $0.827 
平均流通在外普通股份（千股）
基础149,384 155,454 151,401 155,749 
摊薄后150,353 156,829 152,437 157,135 
查看基本报表附注，第 7.
3
目录
墨菲石油公司及其子公司
综合损益表
(未经审计)
三个月结束
9月30日，		九个月结束
9月30日，
(单位：千美元)2024202320242023
净利润包括非控股权益$151,112 $277,804 $422,032 $583,974 
其他综合收益（亏损），净额
外币翻译的净收益（损失）
17,764 (39,353)(34,588)(2,601)
养老和其他离退休福利计划1,174 1,196 2,998 3,347 
其他综合损益
18,938 (38,157)(31,590)746 
包括非控股权益在内的综合收益170,050 239,647 390,442 584,720 
每股，将于 12,018 22,462 65,197 38,701 
归属于墨菲的综合收益$158,032 $217,185 $325,245 $546,019 

查看基本报表附注，第 7.
4
目录
墨菲石油公司及其子公司
综合现金流量表
(未经审计)
九个月结束
9月30日，
(单位：千美元)20242023
经营活动
净利润包括非控股权益$422,032 $583,974 
调整为将净利润调节为持续经营活动提供的净现金
Depreciation, depletion and amortization650,309 648,830 
资产减值34,528 – 
未成功的勘探井成本和先前暂停的勘探成本 69,548 107,825 
递延所得税费用45,136 152,104 
资产退休责任增值39,068 34,196 
长期非现金补偿30,060 42,502 
未开发租赁的摊销7,707 8,215 
衍生工具的按市值核算的变动损失
1,344 – 
来自终止经营的损失
2,123 744 
待定支付。– (139,574)
与待处理条件约定相关的按市值计算的亏损
– 7,113 
其他经营活动，净额(38,260)(97,407)
非现金营运资本减少（增加）
31,835 (142,788)
持续经营活动产生的净现金流量1,295,430 1,205,734 
投资活动
物业增加和干井成本(733,289)(902,295)
收购石油和天然气资产 – (22,773)
出售物业、厂房和设备获得的款项 – 102,913 
投资活动所需净现金(733,289)(822,155)
筹资活动
循环信贷设施借款 350,000 300,000 
循环信贷额度的还款 (350,000)(300,000)
债务养老(50,000)(248,675)
回购普通股(300,132)(75,023)
支付现金分红派息(136,208)(128,657)
股权激励奖励的预扣税(25,310)(14,232)
分配给非控股权益持有人的股份(96,618)(20,052)
融资租赁债务支付(502)(457)
待定支付。– (60,243)
债务融资的发行成本– (20)
筹资活动所需的净现金(608,770)(547,359)
汇率变动对现金及现金等价物的影响778 (414)
现金及现金等价物净减少
(45,851)(164,194)
期初现金及现金等价物余额317,074 491,963 
期末现金及现金等价物$271,223 $327,769 

查看基本报表附注，第 7.
5
目录
墨菲石油公司及其子公司
股东权益合并报表
(未经审计)
三个月结束
9月30日，		九个月结束
9月30日，
(除股份数量外，单位为千美元)2024202320242023
普通股 - 每股$1.00，已授权 450,000,000发行股份195,100,628 2024年9月30日的股份数为 195,100,628 2023年9月30日的股份
期初和期末余额$195,101 $195,101 $195,101 $195,101 
超额股本
期初余额826,861 861,951 880,297 893,578 
限制股票交易和其他(53)44 (70,539)(42,371)
基于股份的补偿8,847 7,137 25,897 17,925 
期末余额835,655 869,132 835,655 869,132 
未分配利润
期初余额6,672,275 6,259,561 6,546,079 6,055,498 
归属于墨菲的净利润139,094 255,342 356,835 545,273 
支付现金分红派息(44,663)(42,789)(136,208)(128,657)
期末余额6,766,706 6,472,114 6,766,706 6,472,114 
累计其他综合损失
期初余额(571,645)(495,783)(521,117)(534,686)
外币翻译收益（损失），扣除所得税17,764 (39,353)(34,588)(2,601)
养老和退休福利计划，扣除所得税1,174 1,196 2,998 3,347 
期末余额(552,707)(533,940)(552,707)(533,940)
库存股
期初余额(1,798,872)(1,586,522)(1,737,566)(1,614,717)
回购普通股(196,187)(75,773)(302,681)(75,773)
获得的限制性股票，扣除放弃部分41 (81)45,229 28,114 
期末余额 - 49,257,269 2024年持有普通股份和 40,627,487 2023年以成本持有普通股份
(1,995,018)(1,662,376)(1,995,018)(1,662,376)
Murphy股东权益5,249,737 5,340,031 5,249,737 5,340,031 
非控股权益
期初余额178,828 154,375 186,859 154,119 
非控制权益净收益12,018 22,462 65,197 38,701 
分配给非控股权益所有者(35,408)(4,069)(96,618)(20,052)
期末余额155,438 172,768 155,438 172,768 
总股本$5,405,175 $5,512,799 $5,405,175 $5,512,799 

查看基本报表附注，第 7.
6
目录
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.

Note A – Basis of Presentation
The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all accruals necessary to present fairly the Company’s financial position as at September 30, 2024 and December 31, 2023, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2024 and 2023, in conformity with U.S. generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2023 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2024 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
None affecting the Company.
Recent Accounting Pronouncements
Expense Disaggregation Disclosures. In November 2024 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. Murphy is currently evaluating the impact of adopting the standard.
Income Tax Disclosures. In December 2023 the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard becomes effective for annual periods beginning after December 15, 2024. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. Murphy is currently evaluating the impact of adopting this standard.
Reportable Segment Disclosures. In November 2023 the FASB issued ASU 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The standard becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The standard requires additional disclosures about reporting segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods. The standard does not affect our determination of reportable segments. Murphy will adopt Update 2023-07 in the period required, and we do not expect the adoption to have a material impact on our consolidated financial position, operating results and cash flows.


Note C – Revenue from Contracts with Customers
Nature of Goods and Services
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily divided into two key geographic segments: the United States (U.S.) and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids (NGL), and natural gas.
For operated oil and natural gas production where the non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP.
U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.
Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C - Revenue from Contracts with Customers (Continued)
The Company’s revenues and other income for the three-month and nine-month periods ended September 30, 2024 and 2023 were as follows.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Thousands of dollars)2024202320242023
Net crude oil and condensate revenue
United States - Onshore
$161,965 $207,448 $450,463 $514,614 
United States - Offshore 1
399,940 568,721 1,382,071 1,549,872 
Canada - Onshore
20,852 20,610 54,305 61,868 
Canada - Offshore
80,226 22,272 178,327 63,273 
Other(795)3,442 3,414 7,086 
Total crude oil and condensate revenue662,188 822,493 2,068,580 2,196,713 
Net natural gas liquids revenue
United States - Onshore
8,134 9,953 23,281 24,763 
United States - Offshore 1
9,812 10,908 29,523 37,078 
Canada - Onshore
2,402 2,539 5,434 7,519 
Total natural gas liquids revenue20,348 23,400 58,238 69,360 
Net natural gas revenue
United States - Onshore
4,265 6,035 11,893 15,623 
United States - Offshore 1
12,311 18,377 35,700 55,311 
Canada - Onshore
54,057 75,584 170,871 204,949 
Total natural gas revenue70,633 99,996 218,464 275,883 
Revenue from production753,169 945,889 2,345,282 2,541,956 
Sales of purchased natural gas
Canada - Onshore
– 7,877 3,742 64,628 
Total sales of purchased natural gas– 7,877 3,742 64,628 
Total revenue from sales to customers753,169 953,766 2,349,024 2,606,584 
(Loss) on derivative instruments(1,344)– (1,344)– 
Gain on sale of assets and other income6,506 5,879 9,834 9,365 
Total revenues and other income$758,331 $959,645 $2,357,514 $2,615,949 
1 Includes revenue attributable to noncontrolling interest in MP GOM.
Contract Balances and Asset Recognition
As of September 30, 2024, and December 31, 2023, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $165.1 million and $193.7 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any revenue contracts that have financing components as of September 30, 2024.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
Performance Obligations
The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company,
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.
As of September 30, 2024, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:
Long-Term Contracts Outstanding at September 30, 2024
LocationCommodityEnd DateDescriptionApproximate Volumes
U.S.Natural Gas and NGLQ2 2030Deliveries from dedicated acreage in Eagle FordAs produced
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD index pricing31 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at CAD fixed pricing124 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at USD fixed pricing25 MMCFD
CanadaNatural GasQ4 2024Contracts to sell natural gas at CAD index pricing28 MMCFD
CanadaNatural GasQ4 2025Contracts to sell natural gas at USD index pricing25 MMCFD
CanadaNatural GasQ4 2025Contracts to sell natural gas at CAD fixed pricing40 MMCFD
CanadaNatural GasQ4 2026Contracts to sell natural gas at USD index pricing49 MMCFD
CanadaNatural GasQ4 2026Contracts to sell natural gas at CAD fixed pricing50 MMCFD
CanadaNatural GasQ4 2027Contracts to sell natural gas at USD index pricing30 MMCFD
CanadaNatural GasQ4 2028Contracts to sell natural gas at USD index pricing10 MMCFD
CanadaNGLQ2 2025Contracts to sell NGL at CAD index pricingAs produced
Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.


Note D – Property, Plant and Equipment
Exploratory Wells
Under FASB guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
As of September 30, 2024, the Company had total capitalized drilling costs pending the determination of proved reserves of $51.1 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2024 and 2023.
(Thousands of dollars)20242023
Beginning balance at January 1$49,118 $171,860 
  Additions pending the determination of proved reserves28,452 40,825 
  Reclassifications to proved properties based on the
  determination of proved reserves		– (1,065)
  Capitalized exploratory well costs charged to expense(26,471)(26,143)
Balance at September 30$51,099 $185,477 
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
Capital additions of $28.5 million are mainly for Ocotillo #1 (Mississippi Canyon 40) exploratory well in the Gulf of Mexico and Hai Su Vang #1 (Block 15/2-17) and Lac Da Hong #1 (Block 15-1/05) exploratory wells in Vietnam. Capitalized well costs charged to dry hole expense of $26.5 million for the nine months ended September 30, 2024 were related to the Hoffe Park #1 (Mississippi Canyon 166) exploratory well in the Gulf of Mexico. The preceding table excludes well costs of $43.0 million and $81.7 million incurred and expensed directly to dry hole for the nine months ended September 30, 2024 and 2023, respectively. In 2024, these costs primarily include $25.8 million for the Orange #1 (Mississippi Canyon 216) and $11.8 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of Mexico. In 2023, the amount primarily includes $80.3 million for the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico.
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.
September 30,
20242023
(Thousands of dollars)AmountNo. of WellsNo. of ProjectsAmountNo. of WellsNo. of Projects
Aging of capitalized well costs:
Zero to one year$28,552 3 3 $– – – 
One to two years– – – 38,817 1 1 
Two to three years– – – 2,698 1 1 
Three years or more22,547 3 3 143,962 4 3 
$51,099 6 6 $185,477 6 5 
Of the $22.5 million of exploratory well costs capitalized more than one year at September 30, 2024, $15.1 million was in Vietnam, $4.7 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 
Impairments
There were no impairments in the three months ended September 30, 2024. There were pre-tax impairments of $34.5 million in the nine months ended September 30, 2024 related to the Calliope field, in the Gulf of Mexico, where operational issues led to a reserve reduction. There were no impairments in the three and nine months ended September 30, 2023.
Divestitures
On September 15, 2023, the Company completed the divestment of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada, effective March 1, 2023, for net cash proceeds of C$139.0 million. No gain or loss was recorded related to this transaction.

Note E – Financing Arrangements and Debt
Revolving Credit Facility
As of September 30, 2024, the Company had an $800.0 million revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility was set to expire on November 17, 2027. At September 30, 2024, the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2024, the interest rate in effect on borrowings under the RCF would have been 7.20%. At September 30, 2024, the Company was in compliance with all covenants related to the RCF.
Subsequent Event - Revolving Credit Facility
On October 7, 2024, the Company entered into a credit agreement governing a $1,200.0 million senior unsecured guaranteed revolving credit facility (New RCF) with a maturity date on October 7, 2029. The New
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note E – Financing Arrangements and Debt (Continued)

RCF, which is effective October 2024, extends the borrowing term and increases the borrowing capacity of the previous RCF. On the date the Company achieves certain credit ratings (Investment Grade Ratings Date), certain covenants will be modified as set forth in the New RCF. In addition, prior to the Investment Grade Ratings Date, the Company will be required to comply with a maximum consolidated leverage ratio of 3.25x and a minimum consolidated interest coverage ratio of 2.50x. From and after the Investment Grade Ratings Date, the Company will be required to comply with a maximum ratio of consolidated total debt to consolidated total capitalization of 60%. Borrowings under the New RCF bear interest at rates based on either the “Alternate Base Rate”, the “Adjusted Term Secured Overnight Financing Rate (SOFR) Rate”, or the “Adjusted Daily Simple SOFR Rate”, respectively, plus the “Applicable Rate”. The “Alternate Base Rate” of interest is the highest of (a) the Wall Street Journal prime rate in effect on such day, (b) the New York Federal Reserve Bank (NYFRB) Rate in effect on such day plus ½ of 1% and (c) the Adjusted Term SOFR Rate for a one-month interest period as published two U.S. Government Securities Business Days prior to such day (or if such day is not a U.S. Government Securities Business Day, the immediately preceding U.S. Government Securities Business Day) plus 1%. The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10%. The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) 0.10%. The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services, respectively, as set forth in the grid included in the full text of the credit agreement governing the New RCF. The Company has incurred $12.4 million in transaction costs and will record the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which will be amortized to interest expense over the term of the New RCF.
Debt Extinguishment
In May 2024, the Company paid a total of $50.5 million to complete the open market repurchases of $26.5 million aggregate principal of its 5.875% senior notes due 2027 (2027 Notes) and $23.5 million aggregate principal of its 6.375% senior notes due 2028 (2028 Notes). The cash costs of the debt extinguishment of $0.5 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2024.
In September 2023, the Company redeemed the remaining $248.7 million principal amount outstanding of its 5.750% senior notes due 2025 (2025 Notes). The non-cash costs of the debt extinguishment of $0.9 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2023.
Debt Offering
On September 19, 2024, the Company announced the public offering (the Offering) of $600.0 million aggregate principal amount of 6.000% senior notes due 2032. This Offering was pursuant to the shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities. Subsequent to quarter end, the shelf registration statement was renewed through October 15, 2027.
Subsequent Event - Debt Offering
On October 3, 2024, the Company closed the Offering of $600.0 million aggregate principal amount of new senior notes that bear interest at a rate of 6.000% per annum and mature on October 1, 2032. The Company has incurred transaction costs of $10.1 million on the issuance of these new notes. The Company will pay interest semi-annually on April 1 and October 1 of each year, beginning April 1, 2025. The proceeds of the $600.0 million notes will be used to fund the repurchase and repayment of debt. To date, the Company has repurchased and canceled an aggregate $521.1 million of its notes, comprised of: $258.8 million of the 2027 Notes, $200.2 million of the 2028 Notes and $62.1 million of the 7.050% senior notes due 2029 (2029 Notes). The total cost of the debt extinguishment was $18.2 million: consisting of cash costs of $14.9 million and non-cash costs of $3.3 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.
Nine Months Ended
September 30,
(Thousands of dollars)20242023
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable $80,603 $(69,689)
(Increase) decrease in inventories1,823 (6,609)
(Increase) decrease in prepaid expenses(8,131)(3,364)
Increase (decrease) in accounts payable and accrued liabilities ¹(43,231)(60,582)
Increase (decrease) in income taxes payable771 (2,544)
Net decrease (increase) in noncash working capital$31,835 $(142,788)
Supplementary disclosures:
Cash income taxes paid, net of refunds$12,519 $12,737 
Interest paid, net of amounts capitalized of $10.8 million in 2024 and $10.4 million in 2023
48,708 78,169 
Non-cash investing activities:
Asset retirement costs capitalized$19,949 $16,219 
(Increase) decrease in capital expenditure accrual(2,177)75,760 
1 Excludes payable balances relating to contingent consideration for prior acquisitions.

Note G – Asset Retirement Obligations
The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.
A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the nine-month periods ended September 30, 2024 and 2023 are shown in the following table.
(Thousands of dollars)September 30, 2024September 30, 2023
Balance at beginning of year$914,763 $911,653 
Accretion39,068 34,196 
Liabilities incurred17,975 16,441 
Revisions of previous estimates2,452 (822)
Liabilities settled(1,982)(89,340)
Changes due to translation of foreign currencies(2,618)(340)
Balance at end of period969,658 871,788 
Current portion of liability 1
(39,693)(12,665)
Noncurrent portion of liability$929,965 $859,123 
1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.
The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

Note H – Employee and Retiree Benefit Plans
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note H – Employee and Retiree Benefit Plans (Continued)
The Company has defined benefit pension plans that are noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans meet the requirements of local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2024 and 2023.
Three Months Ended September 30,
Pension BenefitsOther Postretirement Benefits
(Thousands of dollars)2024202320242023
Service cost$1,706 $1,650 $135 $132 
Interest cost8,398 8,534 782 874 
Expected return on plan assets(8,366)(8,223)– – 
Estimated defined contribution provision54 53 – – 
Amortization of prior service cost (credit)579 155 (133)(133)
Recognized actuarial loss (gain)2,363 2,407 (812)(767)
Total net periodic benefit expense$4,734 $4,576 $(28)$106 
Nine Months Ended September 30,
Pension BenefitsOther Postretirement Benefits
(Thousands of dollars)2024202320242023
Service cost$5,118 $4,950 $405 $396 
Interest cost25,182 25,605 2,346 2,622 
Expected return on plan assets(25,082)(24,671)– – 
Estimated defined contribution provision163 161 – – 
Amortization of prior service cost (credit)1,737 465 (399)(399)
Recognized actuarial loss (gain)7,084 7,222 (2,436)(2,315)
         Total net periodic benefit expense$14,202 $13,732 $(84)$304 
The components of net periodic benefit expense, other than the service cost, are recorded in “Other (loss) income” in the Consolidated Statements of Operations.
During the nine-month period ended September 30, 2024, the Company made contributions of $31.3 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2024 for the Company’s defined benefit pension and postretirement plans is anticipated to be $9.9 million.

Note I – Incentive Plans
The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.
The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s common stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of five million shares are issuable during the term of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the 2020 Long-Term Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Shares underlying awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the Plan.
During the nine months ended September 30, 2024, the Committee granted the following awards from the 2020 Long-Term Plan:
Type of AwardNumber of Awards GrantedGrant DateGrant Date
Fair Value		Valuation Methodology
Performance-based RSUs (TSR) 1
423,640 February 6, 2024$41.95 Monte Carlo
Performance-based RSUs (ROACE) 1
105,980 February 6, 2024$38.08 Average Stock Price
Time-based RSUs (Stock-Settled) 2
658,420 February 6, 2024$38.08 Average Stock Price
Time-based RSUs (Cash-Settled) 2
102,900 February 6, 2024$38.08 Average Stock Price
Performance-based RSUs (TSR) 1
5,830 April 1, 2024$50.81 Monte Carlo
Performance-based RSUs (ROACE) 1
1,450 April 1, 2024$45.98 Average Stock Price
Time-based RSUs (Stock-Settled) 2
4,840 April 1, 2024$45.98 Average Stock Price
Time-based RSUs (Cash-Settled) 2
460 April 1, 2024$45.98 Average Stock Price
Time-based RSUs (Stock-Settled) 2
22,990 August 19, 2024$37.78 Average Stock Price
1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) and Return on Average Capital Employed (ROACE) performance goals and are scheduled to vest three years from the date of grant if performance conditions are met.
2 Time-based RSUs generally vest on the third anniversary of the date of grant.
The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of RSUs and stock options or a combination thereof to the Company’s Non-Employee Directors.
The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan) and the 2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were made under the 2021 NED Plan.
During the nine months ended September 30, 2024, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:
Type of AwardNumber of Awards GrantedGrant DateGrant Date Fair ValueValuation Methodology
Time-Based RSUs 1
47,412 February 07, 2024$37.97 Closing Stock Price
Time-Based RSUs 2
1,230 March 28, 2024$45.70 Closing Stock Price
Time-Based RSUs 2
1,364 June 28, 2024$41.24 Closing Stock Price
Time-Based RSUs 2
1,668 September 30, 2024$33.74 Closing Stock Price
1 Non-employee directors time-based RSUs are scheduled to vest on the first anniversary of the date of grant. Non-employee directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election. These unvested time-based RSUs are included in the table above, will vest in one year, and become deferred RSUs.
2 Effective January 1, 2024, non-employee directors can elect to receive their annual cash retainers in the form of deferred RSUs. Director fees which are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter. Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
In 2017, the Company ceased granting stock options and SARs as a part of the Company’s long-term incentive compensation program. As of September 30, 2024 there were no outstanding stock options or SARs remaining.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:
Nine Months Ended
September 30,
(Thousands of dollars)20242023
Compensation charged against income before tax benefit$27,044 $42,912 
Related income tax benefit recognized in income3,627 7,244 
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

Note J – Earnings Per Share
Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three-month and nine-month periods ended September 30, 2024 and 2023. The following table reports the weighted-average shares outstanding used for these computations.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Weighted-average shares)2024202320242023
Basic method149,384,354 155,453,897 151,400,726 155,749,486 
Dilutive stock options and restricted stock units 968,428 1,375,511 1,036,653 1,385,859 
Diluted method150,352,782 156,829,408 152,437,379 157,135,345 

Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and nine-month periods ended September 30, 2024 and 2023, the Company’s effective income tax rates were as follows:
20242023
Three months ended September 30,1.4%21.9%
Nine months ended September 30,13.3%22.2%
The effective tax rate for the three-month period ended September 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend which resulted in an income tax benefit of $33.7 million.

The effective tax rate for the nine-month period ended September 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rates for the three-month period and nine-month period ended September 30, 2023 were above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note K – Income Taxes (Continued)

are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of September 30, 2024, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2017. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

Note L – Financial Instruments and Risk Management
Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. 
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at September 30, 2024 and 2023.
Commodity Price Risks
During the third quarter of 2024, the Company entered into natural gas swap contracts that will be effective in 2025. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. During the third quarter of 2023, the Company did not have any crude oil or natural gas derivative contracts.
At September 30, 2024, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:
2025
NYMEX HENRY HUB swap contracts:
     Volumes (MMCF/d):20 
     Price per MCF:$3.20 
At September 30, 2024 and December 31, 2023, the fair value of derivative instruments not designated as hedging instruments are presented in the following table:
(Thousands of dollars)Asset (Liability) Derivatives Fair Value
Type of Derivative ContractBalance Sheet LocationSeptember 30, 2024December 31, 2023
Commodity swapsAccounts payable$(1,344)$– 
For the three-month and nine-month periods ended September 30, 2024 and 2023, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
Gain (Loss)Gain (Loss)
(Thousands of dollars)Three Months Ended September 30,Nine Months Ended September 30,
Type of Derivative ContractStatement of Operations Location2024202320242023
Commodity swaps(Loss) on derivative instruments$(1,344)$– $(1,344)$– 
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The fair value measurements for these assets and liabilities at September 30, 2024 and December 31, 2023, are shown in the following table:
September 30, 2024December 31, 2023
(Thousands of dollars)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Liabilities:
Commodity swaps$– $1,344 $– $1,344 $– $– $– $– 
Nonqualified employee savings plan19,225 – – 19,225 17,785 – – 17,785 
$19,225 $1,344 $– $20,569 $17,785 $– $– $17,785 
The fair value of commodity (Henry Hub natural gas) swaps was based on active market quotes for Henry Hub (HH) natural gas. The before tax income effect of changes in the fair value of natural gas derivative contracts is recorded in “(Loss) on derivative instruments” in the Consolidated Statements of Operations.
As of December 31, 2023, there were no outstanding commodity WTI crude oil or HH natural gas swaps and collars contracts subject to fair value measurement, nor were there any commodity swaps and collars liabilities.
The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations.
In 2019, the Company acquired strategic deepwater Gulf of Mexico assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG). Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds were exceeded between 2019 and 2022; and $50 million following first oil from certain development projects. The revenue threshold was not exceeded for 2019 or 2020; however, the threshold was met in 2021 and 2022.
In 2018, the Company, through a subsidiary, acquired Gulf of Mexico producing assets from Petrobras America Inc. (PAI), a subsidiary of Petróleo Brasileiro S.A. Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $150 million if certain price and production thresholds were exceeded beginning in 2019 through 2025; and $50 million carry for PAI development costs in the St. Malo field if certain enhanced oil recovery projects were undertaken. The price and production thresholds were not exceeded for 2019 and 2020; however, the thresholds were met in 2021 and 2022. As of December 31, 2021, Murphy had completely funded the carried interest.
As of the end of the second quarter of 2023, the Company had no remaining liabilities relating to prior acquisitions from PAI and LLOG. During the nine months ended September 30, 2023, the Company paid a total of $199.8 million in contingent consideration payments. In the Consolidated Statements of Cash Flows, $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities”.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at September 30, 2024 and December 31, 2023.
The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at September 30, 2024 and December 31, 2023. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, were minimal.
September 30,December 31,
20242023
(Thousands of dollars)Carrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
Financial liabilities:
Current and long-term debt
$1,280,072 $1,288,682 $1,329,075 $1,265,185 
Note M – Accumulated Other Comprehensive Loss
The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2023 and September 30, 2024 and the changes during the nine-month period ended September 30, 2024 are presented net of taxes in the following table.
(Thousands of dollars)Foreign
Currency
Translation
Gains (Losses)		Retirement
and
Postretirement
Benefit Plan
Adjustments		Total
Balance at December 31, 2023$(381,632)$(139,485)$(521,117)
Components of other comprehensive income (loss):
Before reclassifications to income(34,588)– (34,588)
Reclassifications to income ¹– 2,998 2,998 
Net other comprehensive income (loss)(34,588)2,998 (31,590)
Balance at September 30, 2024$(416,220)$(136,487)$(552,707)
1  Reclassifications before taxes of $4.0 million are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2024. See Note H for additional information. Related income taxes of $1.0 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine-month period ended September 30, 2024.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the U.S. and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.
ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including greenhouse gas (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 of facilities once production has ceased.
Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $1.0 million threshold.
There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, federal methane regulations currently pending or enacted that would, among other things, require increased leak detection monitoring and repairs, stringent restrictions on venting and flaring, a new third-party monitoring program, and new fees on methane emissions from petroleum and natural gas facilities. In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. has since rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021.
The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)

contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Note O – Common Stock Issued and Outstanding
Activity in the number of shares of common stock issued and outstanding for the nine-month periods ended September 30, 2024 and 2023 is shown below.
(Number of shares outstanding)
September 30, 2024September 30, 2023
Beginning of period152,748,642 155,467,319 
Stock options exercised 1
– 520 
Restricted stock awards 1
1,103,503 689,824 
Treasury shares purchased
(8,008,786)(1,684,522)
End of period145,843,359 154,473,141 
1 Shares issued upon exercise of stock options and award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares.
The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of the Company’s common stock. 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 and dependent upon a variety of factors.
During the nine months ended September 30, 2024, the Company repurchased 8.0 million shares of its common stock under the share repurchase program for $300.0 million ($302.7 million including excise taxes and fees). As of September 30, 2024, the Company had $650.1 million of its common stock remaining available to repurchase under the program.
The share repurchase program is a component of the Company’s capital allocation framework, the details of which can be found as part of the Company’s Form 8-K filed on August 4, 2022 and August 8, 2024.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments
Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses, interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia, and U.S. refining and marketing operations as discontinued operations for all periods presented.
Total Assets at September 30, 2024Three Months Ended September 30, 2024Three Months Ended September 30, 2023
(Millions of dollars)External
Revenues		Income
(Loss)		External
Revenues		Income
(Loss)
Exploration and production ¹
United States 2
$7,088.3 $597.0 $138.8 $823.7 $310.3 
Canada2,043.0 157.9 24.2 129.3 10.5 
Other266.6 (0.8)22.4 3.4 (12.5)
Total exploration and production9,397.9 754.1 185.4 956.4 308.3 
Corporate317.6 4.2 (33.7)3.2 (30.1)
Continuing operations9,715.5 758.3 151.7 959.6 278.2 
Discontinued operations, net of tax0.9 – (0.6)– (0.4)
Total$9,716.4 $758.3 $151.1 $959.6 $277.8 
Nine Months Ended September 30, 2024Nine Months Ended September 30, 2023
(Millions of dollars)External
Revenues		Income
(Loss)		External
Revenues		Income
(Loss)
Exploration and production ¹
United States 2
$1,936.1 $459.0 $2,202.2 $705.2 
Canada413.8 52.5 403.3 34.9 
Other3.4 1.5 7.1 (50.0)
Total exploration and production2,353.3 513.0 2,612.6 690.1 
Corporate4.2 (88.9)3.3 (105.4)
Continuing operations2,357.5 424.1 2,615.9 584.7 
Discontinued operations, net of tax– (2.1)– (0.7)
Total$2,357.5 $422.0 $2,615.9 $584.0 
1 Additional detail about the results of oil and natural gas operations is presented in the Exploration and Production Continuing Operations table on page 26.
2 Includes revenue and income attributable to noncontrolling interest in MP GOM.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note Q – Leases
Nature of Leases
The Company has entered into various operating leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment.
Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.
During the second quarter of 2024, the Company exercised an option to extend an operating lease pertaining to a drill ship used in our offshore business. This resulted in an increase of $254.1 million (discounted) to our right-of-use assets and operating lease liabilities at June 30, 2024.
Maturity of Lease Liabilities
(Thousands of dollars)Operating LeasesFinance LeasesTotal
2024$81,903 $265 $82,168 
2025279,908 1,069 280,977 
2026125,462 1,069 126,531 
202769,098 1,069 70,167 
202862,569 1,069 63,638 
Remaining490,391 267 490,658 
Total future minimum lease payments1,109,331 4,808 1,114,139 
Less imputed interest(235,937)(1,277)(237,214)
Present value of lease liabilities 1
$873,394 $3,531 $876,925 
1 Includes both the current and long-term portion of the lease liabilities.

Lease Term and Discount Rate
September 30, 2024December 31, 2023
Weighted average remaining lease term:
Operating leases8 years10 years
Finance leases5 years5 years
Weighted average discount rate:
Operating leases5.7 %5.9 %
Finance leases4.7 %4.7 %
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ITEM 2.  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 unaudited consolidated financial statements and accompanying notes for the quarter ended September 30, 2024 included under Item 1 Financial Statements of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2023. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section.
Overview
Murphy Oil Corporation is a global 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. Our production in the U.S. is primarily from offshore fields in the Gulf of Mexico and onshore in the Eagle Ford Shale area of South Texas. In Canada, we produce from the onshore fields Tupper Montney and Kaybob Duvernay, in British Columbia and Alberta, and we produce from the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin.
Significant Company financial and operational highlights during the third quarter of 2024 were as follows:
•Produced 191,273 barrels of oil equivalent per day (including NCI)
•Maintained quarterly dividend of $0.30 per share or $1.20 per share annualized
•Repurchased $194.1 million ($196.2 million including excise taxes and fees) of common stock, or 5,374,191 shares, at an average price of $36.12 per share
Subsequent to the third quarter of 2024:
•Issued $600.0 million of 6.000% senior notes due 2032, and used proceeds to tender an aggregate $521.1 million of senior notes due 2027, 2028 and 2029
•Entered into new five-year, $1.2 billion senior unsecured credit facility, representing a 50 percent increase from previous facility size

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended September 30, 2024, was $151.7 million, a decrease of $126.5 million compared to the same period in 2023. Lower net income from continuing operations was driven primarily by lower revenues from production ($192.7 million), higher lease operating expenses ($29.5 million), and lower other income ($12.7 million), and was partially offset by lower income tax expense ($76.0 million), lower transportation, gathering and processing expenses ($14.1 million), and lower depreciation, depreciation, depletion and amortization expenses ($13.9 million). Lower revenues were primarily driven by lower oil production in the U.S., combined with lower oil prices. Higher lease operating expenses relate primarily to workover projects in the Gulf of Mexico. Lower other income represents unrealized foreign exchange losses. Lower income tax expense in the current period is driven primarily by lower operating income, in addition to an income tax deduction for prior years’ Australia exploration spend. Lower transportation, gathering and processing expenses and lower depreciation, depletion and amortization expenses were both driven by lower production in the U.S.
For the three months ended September 30, 2024 total hydrocarbon production was 191,273 barrels of oil equivalent per day, a decrease of 8% compared to the third quarter of 2023. The decrease was principally due to lower production in the U.S., primarily in the Gulf of Mexico, due to workover activities and downtime, and in the Eagle Ford Shale, due primarily to the timing of new wells. Decreases in the U.S. were offset by increases in Canada at both Terra Nova, which restarted production in late 2023.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Overview (Continued)
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2024 was $424.1 million, a decrease of $160.6 million compared to the same period of 2023. Lower net income from continuing operations was largely driven by lower revenues from production ($196.7 million), higher lease operating expenses ($129.2 million), and higher impairment of assets ($34.5 million). These were partially offset by lower income tax expense ($102.0 million), lower exploration expenses ($34.1 million), higher other income ($32.8 million), lower interest expense on long-term debt ($26.4 million), and lower transportation, gathering and processing expenses ($17.8 million). Lower revenues from production were primarily driven by downtime in the Gulf of Mexico and Eagle Ford Shale and lower natural gas prices, partially offset by higher year-to-date oil prices, higher production in Canada due to the restart of production at Terra Nova in late 2023, and well performance, combined with lower royalty rates at Tupper Montney. Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico and higher production activity in Canada at Terra Nova, partially offset by lower production handling (PHA) fees in the Gulf of Mexico. Impairment charges related to the Calliope field were recorded in the first quarter of 2024. The decrease in income tax expense primarily relates to lower income tax expenses driven by lower overall income, in addition to an income tax deduction for prior years’ Australia exploration spend. Exploration expense in the current period was primarily due to dry hole expense recorded for multiple wells in the Gulf of Mexico, including Sebastian #1 (Mississippi Canyon 387) and Orange #1 (Mississippi Canyon 216), additional costs related to the Oso #1 (Atwater Valley 138) well, and for previously suspended exploration costs related to an expired lease at Hoffe Park #1 (Mississippi Canyon 166). Higher other income related to unrealized foreign exchange gains and interest income on several outstanding joint interest receivables. Lower interest expense was due to lower debt levels and lower transportation, gathering and processing expenses related to lower production in the U.S.
For the nine months ended September 30, 2024 total hydrocarbon production was 185,286 barrels of oil equivalent per day, a decrease of 4% compared to the same period in 2023. The decrease was principally due to lower production in the U.S., primarily in the Gulf of Mexico due to downtime for workovers, and in the Eagle Ford Shale, due to timing of new wells. Decreases in the U.S. were partially offset by increases in Canada at both Tupper Montney, due to new wells online, and Terra Nova, which restarted production in late 2023.

Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below.
Income (Loss)
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)2024202320242023
Exploration and production
United States$138.8 $310.3 $459.0 $705.2 
Canada24.2 10.5 52.5 34.9 
Other 22.4 (12.5)1.5 (50.0)
Total exploration and production
185.4 308.3 513.0 690.1 
Corporate(33.7)(30.1)(88.9)(105.4)
Income from continuing operations151.7 278.2 424.1 584.7 
Discontinued operations ¹(0.6)(0.4)(2.1)(0.7)
Net income including noncontrolling interest151.1 277.8 422.0 584.0 
Net income attributable to noncontrolling interest
12.0 22.5 65.2 38.7 
Net income attributable to Murphy$139.1 $255.3 $356.8 $545.3 
1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. 
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Exploration and Production Continuing Operations
The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment unless otherwise noted.
The following are summarized income statements for E&P continuing operations:
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)2024202320242023
Revenues and other income
Revenue from production
$753.2 $945.9 $2,345.3 $2,542.0 
Sales of purchased natural gas
– 7.9 3.7 64.6 
Other income
0.9 2.6 4.3 6.0 
Total revenues and other income
754.1 956.4 2,353.3 2,612.6 
Cost and Expenses
Lease operating expenses222.9 193.4 716.8 587.6 
Severance and ad valorem taxes10.5 10.9 31.0 35.1 
Transportation, gathering and processing47.5 61.5 157.5 175.3 
Costs of purchased natural gas– 5.5 3.1 47.4 
Depreciation, depletion and amortization222.1 234.7 643.3 640.4 
Impairments of assets– – 34.5 – 
Accretion of asset retirement obligations13.2 11.7 39.0 34.1 
Total exploration expenses31.2 26.4 118.4 152.5 
Selling and general expenses5.0 10.7 14.0 25.0 
Other 6.7 7.8 (4.7)29.0 
Results of operations before taxes195.0 393.8 600.4 886.2 
Income tax provisions
9.6 85.5 87.4 196.1 
Results of operations (excluding Corporate segment) 1
$185.4 $308.3 $513.0 $690.1 
1 Includes results attributable to a noncontrolling interest in MP GOM.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Pricing
The following table contains the weighted average sales prices for the three-month and nine-month periods ended September 30, 2024 and 2023.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Weighted average sales prices)2024202320242023
Crude oil and condensate – dollars per barrel
United States - Onshore
$75.49 $81.19 $77.55 $76.40 
United States - Offshore 1
75.65 82.94 78.42 76.73 
Canada - Onshore 2
66.18 76.33 68.62 73.01 
Canada - Offshore 2
80.06 94.85 82.83 84.13 
Other
– 77.19 78.20 82.87 
Natural gas liquids – dollars per barrel
United States - Onshore19.05 20.52 19.71 19.76 
United States - Offshore 1
22.50 20.16 23.20 22.01 
Canada - Onshore 2
34.00 37.72 34.64 39.08 
Natural gas – dollars per thousand cubic feet
United States - Onshore1.77 2.32 1.77 2.24 
United States - Offshore 1
2.28 2.84 2.30 2.82 
Canada - Onshore 2
1.34 1.93 1.56 2.07 
1  Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
The following table contains benchmark prices relevant to the Company for the three-month and nine-month periods ended September 30, 2024 and 2023.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Average price for the period)2024202320242023
Oil and NGLs
WTI ($/BBL)$75.10 $82.26 $77.54 $77.39 
Natural gas
NYMEX ($/MMBTU)2.09 2.58 2.18 2.46 
AECO (C$/MCF)
0.69 2.60 1.45 2.75 
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Production Volumes
The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2024 and 2023. For further discussion on volumes, please see “Revenues from Production” section on page 29.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Barrels per day unless otherwise noted)2024202320242023
Net crude oil and condensate
United States - Onshore
23,320 27,772 21,199 24,674 
United States - Offshore 1
59,282 74,843 64,042 74,185 
Canada - Onshore
3,425 2,935 2,888 3,104 
Canada - Offshore
7,880 2,956 7,219 2,778 
Other171 262 221 247 
Total net crude oil and condensate
94,078 108,768 95,569 104,988 
Net natural gas liquids
United States - Onshore
4,640 5,272 4,312 4,590 
United States - Offshore 1
4,739 5,882 4,644 6,170 
Canada - Onshore
768 732 572 705 
Total net natural gas liquids
10,147 11,886 9,528 11,465 
Net natural gas – thousands of cubic feet per day
United States - Onshore
26,223 28,312 24,556 25,571 
United States - Offshore 1
58,747 70,240 56,565 71,764 
Canada - Onshore
437,316 426,725 400,012 361,852 
Total net natural gas
522,286 525,277 481,133 459,187 
Total net hydrocarbons - including NCI 2,3
191,273 208,200 185,286 192,984 
Noncontrolling interest
Net crude oil and condensate – barrels per day(6,188)(5,989)(6,467)(6,181)
Net natural gas liquids – barrels per day(193)(191)(207)(209)
   Net natural gas – thousands of cubic feet per day (1,947)(1,887)(2,008)(1,996)
Total noncontrolling interest 2,3
(6,706)(6,495)(7,009)(6,723)
Total net hydrocarbons - excluding NCI 2,3
184,567 201,705 178,277 186,261 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment unless otherwise noted.

Revenues from Production
The Company’s production revenues by country and product were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)2024202320242023
Revenues from production
United States - Oil
$561.9 $776.3 $1,832.6 $2,064.6 
United States - Natural gas liquids
17.9 20.9 52.8 61.8 
United States - Natural gas
16.6 24.4 47.6 70.9 
Canada - Oil
101.1 42.9 232.6 125.1 
Canada - Natural gas liquids
2.4 2.5 5.4 7.5 
Canada - Natural gas
54.1 75.7 170.9 205.0 
Other - Oil
(0.8)3.4 3.4 7.1 
Total revenue from production
$753.2 $945.9 $2,345.3 $2,542.0 
Revenues from production for the three months ended September 30, 2024 decreased $192.7 million compared to the same period in 2023. Revenue was lower in the Gulf of Mexico, mostly driven by downtime at the Samurai field, as well as hurricane related downtime. Additionally, Eagle Ford Shale revenues decreased due to the natural decline of wells and fewer wells brought online. These decreases were partially offset by new production at Terra Nova in Canada, which restarted production in late 2023. Lower pricing across all products also contributed to the decrease during the period.
Revenues from production for the nine months ended September 30, 2024 decreased $196.7 million compared to the same period in 2023. Lower revenue was driven primarily by workover activities, downtime and timing of new wells in the Gulf of Mexico, fewer new wells brought online in the Eagle Ford Shale, and lower realized natural gas prices in Tupper Montney. These effects were partially offset by production restarting at Terra Nova in late 2023, and higher oil prices.
Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. Sales of purchased 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 26.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Lease Operating and Transportation, Gathering and Processing Expenses
The Company’s total lease operating expenses and transportation, gathering and processing (TGP) expenses by geographic area were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)(Dollars per equivalent barrel)
(Millions of dollars)
(Dollars per equivalent barrel)
20242023202420232024202320242023
Lease operating expenses
United States - Onshore
$32.9 $39.5 $11.03 $11.36 $105.4 $113.4 $13.00 $12.40 
United States - Offshore
136.0 113.7 20.54 13.42 462.3 359.0 21.52 14.27 
Canada - Onshore
35.2 36.7 4.96 5.33 101.4 104.4 5.28 5.97 
Canada - Offshore
18.5 2.8 18.51 12.12 46.7 9.4 21.67 12.45 
Other0.3 0.7 – 15.55 1.0 1.4 23.66 16.49 
Total lease operating expenses
$222.9 $193.4 $12.60 $10.12 $716.8 $587.6 $14.05 $11.16 
TGP expenses
United States - Onshore
$2.2 $3.0 $0.73 $0.87 $7.3 $9.7 $0.89 $1.07 
United States - Offshore
24.1 38.9 3.64 4.59 89.8 109.4 4.18 4.35 
Canada - Onshore
20.1 18.7 2.84 2.71 56.9 53.2 2.96 3.03 
Canada - Offshore
1.1 0.9 1.06 4.00 3.5 3.0 1.63 4.05 
Total TGP expenses
$47.5 $61.5 $2.68 $3.22 $157.5 $175.3 $3.09 $3.33 
For the three months ended September 30, 2024 lease operating expenses increased by $29.5 million and TGP expenses decreased by $14.0 million compared to the same period in 2023. Higher lease operating expenses were due to workover activity in the Gulf of Mexico and higher production at Terra Nova and were partially offset by lower PHA fees in the Gulf of Mexico. Lower TGP expenses during the quarter were a result of lower production volumes in the Gulf of Mexico.
For the nine months ended September 30, 2024, lease operating expenses increased by $129.2 million and TGP expenses decreased by $17.8 million compared to the same period in 2023. Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico, primarily at the Neidermeyer field, and higher production at Terra Nova, and were partially offset by lower PHA fees in the Gulf of Mexico. Lower TGP expenses resulted primarily from lower production volumes in the Gulf of Mexico.

Depreciation, Depletion and Amortization Expense
The Company’s depreciation, depletion and amortization (DD&A) expense by geographic area were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)(Dollars per equivalent barrel)
(Millions of dollars)
(Dollars per equivalent barrel)
20242023202420232024202320242023
DD&A expense
United States - Onshore
$88.0 $91.5 $29.60 $26.32 $237.2 $240.8 $29.25 $26.31 
United States - Offshore
91.3 102.1 13.78 12.05 291.1 291.0 13.55 11.57 
Canada - Onshore
34.5 38.1 4.87 5.53 93.5 99.8 4.87 5.70 
Canada - Offshore
8.3 2.3 8.27 10.02 20.6 7.2 9.58 9.59 
Other– 0.7 – 16.49 0.9 1.6 20.82 19.01 
Total DD&A expense
$222.1 $234.7 $12.56 $12.28 $643.3 $640.4 $12.61 $12.17 
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
DD&A expense for the three months ended September 30, 2024 decreased by $12.6 million compared to the same period in 2023. The decrease is primarily due to lower volumes in the Gulf of Mexico and at Eagle Ford Shale, partially offset by higher volumes in Canada Offshore and Onshore and higher rates in the U.S. due to development drilling.
DD&A expense for the nine months ended September 30, 2024 increased by $2.9 million compared to the same period in 2023. Higher DD&A expense from Canada E&P primarily related to increased volumes at Terra Nova, partially offset by lower volumes in the U.S. and higher rates in the U.S., primarily due to development drilling at various offshore platforms.

Impairment of Assets
For the three months ended September 30, 2024, there were no impairments. For the nine months ended September 30, 2024, the Company impaired assets for $34.5 million, related to the Calliope field in the Gulf of Mexico, as a result of operational issues that led to a reserve reduction.
There were no impairments in the three and nine months ended September 30, 2023.

Exploration Expenses
The Company’s exploration expenses were as follows:
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)2024202320242023
Exploration expenses
Dry holes and previously suspended exploration costs$11.2 $11.3 $69.5 $107.8 
Geological and geophysical12.7 4.3 22.3 15.6 
Other exploration5.4 8.0 18.9 20.9 
Undeveloped lease amortization1.9 2.8 7.7 8.2 
Total exploration expenses
$31.2 $26.4 $118.4 $152.5 
Exploration expenses for the three months ended September 30, 2024 increased by $4.8 million compared to the prior year, primarily as a result of higher geological and geophysical costs in the Gulf of Mexico in the current period. Dry hole costs in the current period represented costs associated with the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the U.S. Gulf of Mexico that encountered non-commercial hydrocarbons in the third quarter of 2024. In the third quarter of 2023, we recorded dry hole costs related to the Chinook #7 (Walker Ridge 425) exploration well in the U.S. Gulf of Mexico.
Exploration expenses for the nine months ended September 30, 2024 decreased by $34.1 million compared to the same period in 2023. In the current period, dry hole costs were recorded for the Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and for the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the U.S. Gulf of Mexico. In 2023, we recorded previously suspended exploration costs for the Cholula-1EXP well in Mexico and dry hole costs for the Chinook #7 (Walker Ridge 425) exploration well in the U.S. Gulf of Mexico.

Other
Other expenses for the three and nine months ended September 30, 2024 decreased by $1.1 million and $33.7 million, respectively, compared to the same periods in 2023. For the three months ended September 30, 2024 the decrease is primarily due to the absence of other operating expenses in Canada related to the Terra Nova life extension project. For the nine months ended September 30, 2024 the decrease was due to a combination of interest income received and a favorable state tax settlement related to U.S. Onshore activities.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Income Taxes
Income taxes for the three and nine months ended September 30, 2024 decreased by $75.9 million and $108.7 million, respectively, compared to the same periods in 2023. Lower income taxes for each period, respectively, were primarily the result of lower year-to-date pre-tax income, and an income tax deduction for prior years’ Australia exploration spend.

Corporate
Corporate activities included interest expense and income, foreign exchange effects and corporate overhead not allocated to E&P.
Corporate activities reported a loss of $33.7 million for the three months ended September 30, 2024, an unfavorable variance of $3.6 million compared to the same period of 2023. The unfavorable variance was primarily due to unrealized foreign exchange losses ($14.0 million), partially offset by decreased interest expense ($8.8 million). Lower interest expense for the current period was primarily due to lower overall debt levels.
Corporate activities reported a loss of $88.9 million for the nine months ended September 30, 2024, a favorable variance of $16.5 million compared to the same period of 2023. The favorable variance was primarily due to lower interest expense ($26.6 million) and unrealized foreign exchange gains ($10.1 million) and was partially offset by increased selling and general expense ($15.6 million) and lower income tax benefits ($6.7 million). Lower interest expense for the current period was primarily due to lower overall debt levels. Higher selling and general expenses for the nine months ended September 30, 2024 were primarily attributable to timing of corporate donations. Lower income tax benefit was the result of lower pre-tax losses.

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 the New 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. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities.

Cash Flows
The following table presents the Company’s cash flows for the periods presented:
Nine Months Ended
September 30,
(Thousands of dollars)20242023
Net cash provided by (required by):
Net cash provided by continuing operations activities$1,295.4 $1,205.7 
Net cash required by investing activities
(733.3)(822.2)
Net cash required by financing activities
(608.8)(547.4)
Effect of exchange rate changes on cash and cash equivalents0.8 (0.4)
Net decrease in cash and cash equivalents
$(45.9)$(164.2)
Cash Provided by Continuing Operations Activities
Net cash provided by continuing operations activities for the nine months ended September 30, 2024 was $89.7 million higher compared to the same period in 2023. The increase in cash flows from operations activities was primarily attributable to a decrease in non-cash working capital in the current period, compared to an increase in the prior period ($174.6 million), no contingent consideration payments related to prior Gulf of
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Mexico acquisitions in 2024 (2023: $139.6 million), changes in other operating activities, net ($59.1 million), an increase in other income ($32.8 million), and a decrease in interest expense ($26.4 million). These were partially offset by lower revenue from production ($196.7 million), and an increase in lease operating expenses ($129.2 million). The increase due to changes in non-cash working capital is primarily due to lower accounts receivable, partially offset by lower accounts payable. The decreases in accounts receivable and accounts payable are primarily due to lower overall production volumes and gas prices, other receivable settlements, and exploration activities in the Gulf of Mexico. The increase due to changes in other operating activities is primarily due to spend on asset retirement obligations in the prior period.
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 the nine months ended September 30, 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.
Cash Required by Investing Activities
Net cash required by investing activities for the nine months ended September 30, 2024 was $88.9 million lower compared to the same period in 2023. The decrease was due to lower property additions and dry hole costs ($169.0 million), partially offset by cash inflows from the sale of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets Kaybob properties ($102.9 million) in 2023.
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Nine Months Ended
September 30,
(Millions of dollars)20242023
Property additions and dry hole costs per cash flow statements $733.3 $902.3 
Acquisition of oil properties per the cash flow statements
– 22.8 
Geophysical and other exploration expenses35.5 30.1 
Capital expenditure accrual changes and other7.8 (69.5)
Total capital expenditures$776.6 $885.7 
Total accrual basis capital expenditures are shown below.
Nine Months Ended
September 30,
(Millions of dollars)20242023
Capital Expenditures
Exploration and production$760.2 $870.3 
Corporate16.4 15.4 
Total capital expenditures$776.6 $885.7 
Lower capital expenditures in the nine months ended September 30, 2024 compared to the same period of 2023 was primarily attributable to lower exploration expenditures in the Gulf of Mexico, lower field development costs due to the Terra Nova asset life extension project ending in 2023, and lower development drilling costs at Eagle Ford Shale and Tupper Montney, partially offset by higher development expenditures at various Gulf of Mexico fields.
Capital expenditures in 2024 primarily relate to development drilling and field development activities at Eagle Ford Shale ($246.8 million), at the Khaleesi, Mormont and Samurai fields, and the non-operated St. Malo and Lucius fields in the Gulf of Mexico ($235.7 million), and at Tupper Montney ($75.4 million), Kaybob Duvernay
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
($26.3 million), and the non-operated Hibernia field ($15.2 million) in Canada. Other international field development activities were ($30.6 million), and total exploration costs were $123.4 million.
Exploration costs in 2024 were primarily comprised of activities in the Gulf of Mexico related to the Sebastian #1 (Mississippi Canyon 387), Orange #1 (Mississippi Canyon 216), and Oso #1 (Atwater Valley 138) exploration wells. Sebastian #1 and Orange #1 encountered non-commercial hydrocarbons during 2024. Oso #1 encountered non-commercial hydrocarbons in 2023, and operations completed in 2024. Additional exploratory costs relate to the Ocotillo #1 (Mississippi Canyon 40) exploration well.
Cash Required by Financing Activities
Net cash required by financing activities for the nine months ended September 30, 2024 increased by $61.4 million compared to the same period in 2023. In 2024, the cash used in financing activities was principally for the repurchase of common shares ($300.1 million), cash dividends to shareholders of $0.90 per share ($136.2 million), withholding tax on stock-based incentive awards ($25.3 million), distributions to the noncontrolling interest in the Gulf of Mexico ($96.6 million), and debt repurchases of $50.0 million. In 2023, there were debt repurchases ($248.7 million), cash dividends to shareholders ($128.7 million), the repurchase of common shares ($75.0 million), withholding tax on stock-based incentive awards ($14.2 million), distributions to the noncontrolling interest in the Gulf of Mexico ($20.1 million), and contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Continuing Operations Activities” section.

Liquidity
At September 30, 2024 the Company had approximately $1.1 billion of liquidity consisting of $271.2 million in cash and cash equivalents and $799.6 million available on its committed senior unsecured RCF with a major banking consortium.
The Company’s $800.0 million senior unsecured RCF was set to expire in November 2027 and as of September 30, 2024 the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the facility. At September 30, 2024 the interest rate in effect on borrowings under the facility would have been 7.20%. At September 30, 2024 the Company was in compliance with all covenants related to the RCF. Subsequent to quarter end, on October 7, 2024, the Company entered into a New RCF, a credit agreement governing a $1,200.0 million senior unsecured revolving credit facility with a maturity date in October 2029, which replaced the prior RCF.
Cash and invested cash are maintained in several operating locations outside the U.S. As of September 30, 2024 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $101.6 million, the majority of which was held in Canada ($72.3 million). 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.
Working Capital
(Millions of dollars)September 30, 2024December 31, 2023
Working capital
Total current assets$629.6 $752.2 
Total current liabilities884.8 846.5 
Net working capital liability
$(255.2)$(94.3)
As of September 30, 2024 net working capital decreased by $160.9 million compared to December 31, 2023. The decrease was primarily attributable to lower accounts receivable ($80.9 million), lower cash balance ($45.9 million), and higher operating lease liabilities ($45.5 million), and was partially offset by lower accounts payable ($17.1 million).
Lower accounts receivable was primarily due to lower revenues. Higher operating lease liabilities were primarily attributable to the current portion of lease extensions recorded during the period related to a drill ship in the
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
U.S. Gulf of Mexico (See Note Q for additional detail). Lower accounts payable were primarily due to lower revenue related payables and other timing of cash payments.
Capital Employed
A summary of capital employed at September 30, 2024 and December 31, 2023 follows.
September 30, 2024December 31, 2023
(Millions of dollars)Amount%Amount%
Capital employed
Long-term debt$1,279.3 19.6 %$1,328.4 19.9 %
Murphy shareholders' equity5,249.7 80.4 %5,362.8 80.1 %
Total capital employed$6,529.0 100.0 %$6,691.2 100.0 %
At September 30, 2024 long-term debt of $1,279.3 million decreased by $49.1 million compared to December 31, 2023, primarily as a result of the open market repurchase of $50.0 million. The total of the fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.2%.
Murphy shareholders’ equity decreased by $113.1 million in 2024, primarily due to shares repurchased ($302.7 million, including excise tax), cash dividends paid ($136.2 million) and unrealized foreign currency translation losses ($34.6 million), partially offset by net income earned ($356.8 million). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 6 of this Form 10-Q report.

Critical Accounting Estimates
As of September 30, 2024 there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2023.

Accounting Changes and Recent Accounting Pronouncements
See Note B to the Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.


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ITEM 2.  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, earnings before interest, taxes, depreciation and amortization (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 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, and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.
The following table reconciles reported net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars, except per share amounts)
2024202320242023
Net income attributable to Murphy (GAAP) 1
$139.1 $255.3 $356.8 $545.3 
Discontinued operations loss 0.6 0.4 2.1 0.7 
Net income from continuing operations attributable to Murphy
139.7 255.7 358.9 546.0 
Adjustments:
Impairment of assets– – 34.5 – 
Write-off of previously suspended exploration well– – 26.1 17.1 
Foreign exchange loss (gain)5.4 (8.6)(10.6)(0.3)
Mark-to-market loss on derivative instruments1.3 – 1.3 – 
Mark-to-market loss on contingent consideration– – – 7.1 
Total adjustments, before taxes6.7 (8.6)51.3 23.9 
Income tax (benefit) expense related to adjustments
(1.7)2.2 (10.5)(1.4)
Tax benefits on investments in foreign areas(34.0)– (34.0)– 
Total adjustments after taxes(29.0)(6.4)6.8 22.5 
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)
$110.7 $249.3 $365.7 $568.5 
Net income from continuing operations per average diluted share (GAAP)
$0.93 $1.63 $2.35 $3.47 
Adjusted net income from continuing operations per average diluted share (Non-GAAP)
$0.74 $1.59 $2.40 $3.62 
1  Excludes amounts attributable to a noncontrolling interest in MP GOM.


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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)

The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.
Three Months Ended
September 30,		Nine Months Ended
September 30,
(Millions of dollars)2024202320242023
Net income attributable to Murphy (GAAP) 1
$139.1 $255.3 $356.8 $545.3 
Income tax expense2.2 78.1 64.9 166.8 
Interest expense, net21.3 30.0 62.3 88.7 
Depreciation, depletion and amortization expense 1
215.7 231.5 625.8 630.8 
EBITDA attributable to Murphy (Non-GAAP)378.3 594.9 1,109.8 1,431.6 
Impairment of asset– – 34.5 – 
Write-off of previously suspended exploration well– – 26.1 17.1 
Accretion of asset retirement obligations 1
11.7 10.4 34.9 30.4 
Foreign exchange loss (gain) 5.4 (8.6)(10.6)(0.3)
Mark-to-market loss on derivative instruments1.3 – 1.3 – 
Mark-to-market loss on contingent consideration– – – 7.1 
Discontinued operations loss0.6 0.4 2.1 0.7 
Adjusted EBITDA attributable to Murphy (Non-GAAP)$397.3 $597.1 $1,198.1 $1,486.6 
1  Excludes amounts attributable to a noncontrolling interest in MP GOM.


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ITEM 2.  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 29, lower average crude oil and natural gas pricing during the third quarter of 2024 compared to same period in 2023 directly impacted the Company’s product sales revenue.
As of close on November 5, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:
20242025
WTI ($/BBL)71.9969.92
NYMEX ($/MMBTU)2.673.00
AECO (US$ Equivalent/MCF)1.311.45
Similar to the overall inflation 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. For the fourth quarter of 2024, production is expected to average between 181.5 and 189.5 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.
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 and August 8, 2024. The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of the Company’s common stock.
Subsequent to quarter end, on October 3, 2024, the Company closed the Offering of $600.0 million aggregate principal amount of new senior notes that bear interest at a rate of 6.000% per annum and mature on October 1, 2032, the proceeds of which will be used for the repayment of debt. To date, the Company has repurchased and canceled $258.8 million of the 2027 Notes, $200.2 million of the 2028 Notes and $62.1 million of the 2029 Notes. In addition, on October 7, 2024, the Company entered into a credit agreement governing a $1,200.0 million New RCF with a maturity date on October 7, 2029. Further details of these transactions can be found in the Company’s Form 8-K filed on October 3, 2024 and October 7, 2024, respectively.
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 RCF (see Note E).
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Outlook (Continued)
As of November 5, 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/MCFRemaining Period
AreaCommodityTypeStart DateEnd Date
CanadaNatural GasFixed price forward sales162 C$2.3910/1/202412/31/2024
CanadaNatural GasFixed price forward sales40 C$2.751/1/202512/31/2025
CanadaNatural GasFixed price forward sales50 C$3.031/1/202612/31/2026
CanadaNatural GasFixed price forward sales25 US$1.9810/1/202410/31/2024
CanadaNatural GasFixed price forward sales15 US$1.9811/1/202412/31/2024
Volumes
(MMCF/d)
Price/MCFRemaining Period
AreaCommodityTypeStart DateEnd Date
United StatesNatural GasFixed price derivative swap20 US$3.201/1/202512/31/2025
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Forward-Looking Statements
This Form 10-Q 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 “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) and on page 42 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. 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.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to this Form 10-Q report, Murphy, at times, makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
There were commodity transactions in place at September 30, 2024, covering certain future U.S. natural gas sales volumes for the remainder of 2025. A 10% increase in the respective benchmark price of these commodities would have increased the net payable associated with these derivative contracts by approximately $2.5 million, while a 10% decrease would have decreased the recorded net payable by a similar amount.
There were no derivative foreign exchange contracts in place at September 30, 2024.

ITEM 4.  CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, 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) are 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.
During the quarter ended September 30, 2024, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS
The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in the Company’s 2023 Form 10-K filed on February 23, 2024. The Company has not identified any additional risk factors not previously disclosed in its 2023 Form 10-K report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchase of Equity Securities:
The following table summarizes repurchases of our common stock occurring in the third quarter of 2024.
PeriodTotal Number of Shares Purchased
Average Price Paid Per Share1
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 Programs 2,3
(in thousands)
July 1 through July 31, 2024329,123 $39.87 329,123 $331,000 
August 1 through August 31, 20242,152,744 $37.63 2,152,744 $750,000 
September 1 through September 30, 20242,892,324 $34.57 2,892,324 $650,000 
1 Amounts exclude 1% excise tax and fees on share repurchases.
2 In August 2024, the Company’s Board of Directors authorized an additional $500 million increase in the share repurchase program bringing the total amount the Company can repurchase to $1,100 million of the Company’s common stock. 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. Since the inception of the share repurchase program through to the end of the third quarter of 2024, the Company has repurchased 11,419,944 shares of its common stock in open-market transactions for $449.9 million, excluding taxes and fees.

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ITEM 5. OTHER INFORMATION
During the three months ended September 30, 2024, 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.

ITEM 6. EXHIBITS
The Exhibit Index on page 45 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
MURPHY OIL CORPORATION
(Registrant)
By/s/ PAUL D. VAUGHAN
Paul D. Vaughan
Vice President and Controller
(Chief Accounting Officer and Duly Authorized Officer)
November 7, 2024
(Date)
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EXHIBIT INDEX
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 are either not required or not applicable.
Exhibit
No.
101. INSInline XBRL Instance Document
101. SCHInline XBRL Taxonomy Extension Schema Document
101. CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101. DEFInline XBRL Taxonomy Extension Definition Linkbase Document
101. LABInline XBRL Taxonomy Extension Labels Linkbase Document
101. PREInline XBRL Taxonomy Extension Presentation Linkbase
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

45