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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

(Mark One)
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2024
OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission file number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)

Delaware | 71-0361522
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-200 | 77024
Houston, | Texas | (Zip Code)
(Address of principal executive offices) |
(281) | 675-9000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class | Trading Symbol | Name of each exchange on which registered
Common Stock, $1.00 Par Value | MUR | New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.

Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2024 was 150,887,425.

MURPHY OIL CORPORATION
TABLE OF CONTENTS

| Page |
Part I – Financial Information |  |
Item 1. Financial Statements | 2 |
Consolidated Balance Sheets | 2 |
Consolidated Statements of Operations | 3 |
Consolidated Statements of Comprehensive Income | 4 |
Consolidated Statements of Cash Flows | 5 |
Consolidated Statements of Stockholders’ Equity | 6 |
Notes to Consolidated Financial Statements | 7 |
Note A – Basis of Presentation | 7 |
Note B – New Accounting Principles and Recent Accounting Pronouncements | 7 |
Note C – Revenue from Contracts with Customers | 7 |
Note D – Property, Plant and Equipment | 10 |
Note E – Financing Arrangements and Debt | 11 |
Note F – Other Financial Information | 11 |
Note G – Asset Retirement Obligations | 12 |
Note H – Employee and Retiree Benefit Plans | 13 |
Note I – Incentive Plans | 13 |
Note J – Earnings Per Share | 15 |
Note K – Income Taxes | 15 |
Note L – Financial Instruments and Risk Management | 16 |
Note M – Accumulated Other Comprehensive Loss | 18 |
Note N – Environmental and Other Contingencies | 18 |
Note O – Common Stock Issued and Outstanding | 20 |
Note P – Business Segments | 21 |
Note Q – Leases | 22 |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 23 |
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 40 |
Item 4. Controls and Procedures | 40 |
Part II – Other Information |  |
Item 1. Legal Proceedings | 41 |
Item 1A. Risk Factors | 41 |
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 41 |
Item 5. Other Information | 42 |
Item 6. Exhibits | 42 |
Signature | 43 |

1

Table of Contents
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

(Thousands of dollars, except share amounts) | June 30, 2024 |  | December 31, 2023
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 333,619 |  |  | $ | 317,074 |
Accounts receivable, net | 336,965 |  |  | 343,992 |
Inventories | 51,811 |  |  | 54,454 |
Prepaid expenses | 35,053 |  |  | 36,674 |
Total current assets | 757,448 |  |  | 752,194 |
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $13,495,406 in 2024 and $13,135,385 in 2023 | 8,214,554 |  |  | 8,225,197 |
Operating lease assets | 885,582 |  |  | 745,185 |
Deferred income taxes | – |  |  | 435 |
Deferred charges and other assets | 36,134 |  |  | 43,686 |
Total assets | $ | 9,893,718 |  |  | $ | 9,766,697 |
LIABILITIES AND EQUITY |  |  |
Current liabilities |  |  |
Current maturities of long-term debt, finance lease | $ | 739 |  |  | $ | 723 |
Accounts payable | 507,753 |  |  | 446,891 |
Income taxes payable | 20,001 |  |  | 21,007 |
Other taxes payable | 29,669 |  |  | 29,339 |
Operating lease liabilities | 254,780 |  |  | 207,840 |
Other accrued liabilities | 114,690 |  |  | 140,745 |
Total current liabilities | 927,632 |  |  | 846,545 |
Long-term debt, including finance lease obligation | 1,279,310 |  |  | 1,328,352 |
Asset retirement obligations | 923,696 |  |  | 904,051 |
Deferred credits and other liabilities | 291,110 |  |  | 309,605 |
Non-current operating lease liabilities | 645,043 |  |  | 551,845 |
Deferred income taxes | 324,379 |  |  | 276,646 |
Total liabilities | $ | 4,391,170 |  |  | $ | 4,217,044 |
Equity |  |  |
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued | $ | – |  |  | $ | – |
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2024 and 195,100,628 shares in 2023 | 195,101 |  |  | 195,101 |
Capital in excess of par value | 826,861 |  |  | 880,297 |
Retained earnings | 6,672,275 |  |  | 6,546,079 |
Accumulated other comprehensive loss | (571,645) |  |  | (521,117) |
Treasury stock | (1,798,872) |  |  | (1,737,566) |
Murphy Shareholders' Equity | 5,323,720 |  |  | 5,362,794 |
Noncontrolling interest | 178,828 |  |  | 186,859 |
Total equity | 5,502,548 |  |  | 5,549,653 |
Total liabilities and equity | $ | 9,893,718 |  |  | $ | 9,766,697 |

See Notes to Consolidated Financial Statements, page 7.
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Thousands of dollars, except per share amounts) | 2024 |  | 2023 |  | 2024 |  | 2023
Revenues and other income |  |  |  |  |  |  |
Revenue from production | $ | 797,510 |  |  | $ | 799,836 |  |  | $ | 1,592,113 |  |  | $ | 1,596,067 |
Sales of purchased natural gas | 3,497 |  |  | 13,014 |  |  | 3,742 |  |  | 56,751 |
Total revenue from sales to customers | 801,007 |  |  | 812,850 |  |  | 1,595,855 |  |  | 1,652,818 |
Gain on sale of assets and other income | 1,764 |  |  | 1,738 |  |  | 3,328 |  |  | 3,486 |
Total revenues and other income | 802,771 |  |  | 814,588 |  |  | 1,599,183 |  |  | 1,656,304 |
Costs and expenses |  |  |  |  |  |  |
Lease operating expenses | 259,628 |  |  | 194,292 |  |  | 493,892 |  |  | 394,276 |
Severance and ad valorem taxes | 10,417 |  |  | 12,765 |  |  | 20,503 |  |  | 24,205 |
Transportation, gathering and processing | 53,470 |  |  | 59,868 |  |  | 110,023 |  |  | 113,790 |
Costs of purchased natural gas | 2,987 |  |  | 9,657 |  |  | 3,147 |  |  | 41,926 |
Exploration expenses, including undeveloped lease amortization | 42,677 |  |  | 115,793 |  |  | 87,106 |  |  | 125,975 |
Selling and general expenses | 22,893 |  |  | 25,345 |  |  | 54,054 |  |  | 43,653 |
Depreciation, depletion and amortization | 215,543 |  |  | 215,667 |  |  | 426,677 |  |  | 411,337 |
Accretion of asset retirement obligations | 13,053 |  |  | 11,364 |  |  | 25,827 |  |  | 22,521 |
Other operating (income) expense | (2,219) |  |  | 4,960 |  |  | 5,047 |  |  | 16,948 |
Impairment of assets | – |  |  | – |  |  | 34,528 |  |  | – |
Total costs and expenses | 618,449 |  |  | 649,711 |  |  | 1,260,804 |  |  | 1,194,631 |
Operating income from continuing operations | 184,322 |  |  | 164,877 |  |  | 338,379 |  |  | 461,673 |
Other income (loss) |  |  |  |  |  |  |
Other income (loss) | 26,245 |  |  | (7,694) |  |  | 37,796 |  |  | (7,767) |
Interest expense, net | (20,986) |  |  | (29,856) |  |  | (41,007) |  |  | (58,711) |
Total other income (loss) | 5,259 |  |  | (37,550) |  |  | (3,211) |  |  | (66,478) |
Income from continuing operations before income taxes | 189,581 |  |  | 127,327 |  |  | 335,168 |  |  | 395,195 |
Income tax expense | 32,676 |  |  | 34,870 |  |  | 62,733 |  |  | 88,703 |
Income from continuing operations | 156,905 |  |  | 92,457 |  |  | 272,435 |  |  | 306,492 |
Loss from discontinued operations, net of income taxes | (643) |  |  | (602) |  |  | (1,515) |  |  | (323) |
Net income including noncontrolling interest | 156,262 |  |  | 91,855 |  |  | 270,920 |  |  | 306,169 |
Less: Net income (loss) attributable to noncontrolling interest | 28,523 |  |  | (6,431) |  |  | 53,179 |  |  | 16,239 |
NET INCOME ATTRIBUTABLE TO MURPHY | $ | 127,739 |  |  | $ | 98,286 |  |  | $ | 217,741 |  |  | $ | 289,930 |
INCOME (LOSS) PER COMMON SHARE – BASIC |  |  |  |  |  |  |
Continuing operations | $ | 0.84 |  |  | $ | 0.63 |  |  | $ | 1.44 |  |  | $ | 1.86 |
Discontinued operations | – |  |  | – |  |  | (0.01) |  |  | – |
Net income | $ | 0.84 |  |  | $ | 0.63 |  |  | $ | 1.43 |  |  | $ | 1.86 |
INCOME (LOSS) PER COMMON SHARE – DILUTED |  |  |  |  |  |  |
Continuing operations | $ | 0.83 |  |  | $ | 0.62 |  |  | $ | 1.43 |  |  | $ | 1.84 |
Discontinued operations | – |  |  | – |  |  | (0.01) |  |  | – |
Net income | $ | 0.83 |  |  | $ | 0.62 |  |  | $ | 1.42 |  |  | $ | 1.84 |
Cash dividends per common share | $ | 0.300 |  |  | $ | 0.275 |  |  | $ | 0.600 |  |  | $ | 0.550 |
Average common shares outstanding (thousands) |  |  |  |  |  |  |
Basic | 152,153 |  |  | 156,127 |  |  | 152,409 |  |  | 155,976 |
Diluted | 153,144 |  |  | 157,299 |  |  | 153,480 |  |  | 157,308 |

See Notes to Consolidated Financial Statements, page 7.
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Thousands of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Net income including noncontrolling interest | $ | 156,262 |  |  | $ | 91,855 |  |  | $ | 270,920 |  |  | $ | 306,169 |
Other comprehensive (loss) income, net of tax |  |  |  |  |  |  |
Net (loss) gain from foreign currency translation | (16,824) |  |  | 33,083 |  |  | (52,352) |  |  | 36,752 |
Retirement and postretirement benefit plans | 914 |  |  | 1,053 |  |  | 1,824 |  |  | 2,151 |
Other comprehensive (loss) income | (15,910) |  |  | 34,136 |  |  | (50,528) |  |  | 38,903 |
Comprehensive income including noncontrolling interest | $ | 140,352 |  |  | $ | 125,991 |  |  | $ | 220,392 |  |  | $ | 345,072 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | 28,523 |  |  | (6,431) |  |  | 53,179 |  |  | 16,239 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY | $ | 111,829 |  |  | $ | 132,422 |  |  | $ | 167,213 |  |  | $ | 328,833 |

See Notes to Consolidated Financial Statements, page 7.
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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

| Six Months Ended June 30,
(Thousands of dollars) | 2024 |  | 2023
Operating Activities |  |  |
Net income including noncontrolling interest | $ | 270,920 |  |  | $ | 306,169 |
Adjustments to reconcile net income to net cash provided by continuing operations activities |  |  |
Depreciation, depletion and amortization | 426,677 |  |  | 411,337 |
Impairment of assets | 34,528 |  |  | – |
Unsuccessful exploration well costs and previously suspended exploration costs | 58,280 |  |  | 96,533 |
Deferred income tax expense | 53,928 |  |  | 92,557 |
Accretion of asset retirement obligations | 25,827 |  |  | 22,521 |
Long-term non-cash compensation | 21,823 |  |  | 22,076 |
Amortization of undeveloped leases | 5,778 |  |  | 5,369 |
Loss from discontinued operations | 1,515 |  |  | 323 |
Contingent consideration payment | – |  |  | (139,574) |
Mark-to-market loss on contingent consideration | – |  |  | 7,113 |
Other operating activities, net | (33,959) |  |  | (59,417) |
Net decrease (increase) in noncash working capital | 1,126 |  |  | (15,340) |
Net cash provided by continuing operations activities | 866,443 |  |  | 749,667 |
Investing Activities |  |  |
Property additions and dry hole costs | (516,876) |  |  | (694,753) |
Net cash required by investing activities | (516,876) |  |  | (694,753) |
Financing Activities |  |  |
Borrowings on revolving credit facility | 200,000 |  |  | 200,000 |
Repayment of revolving credit facility | (200,000) |  |  | (200,000) |
Retirement of debt | (50,000) |  |  | – |
Repurchase of common stock | (105,887) |  |  | – |
Cash dividends paid | (91,545) |  |  | (85,867) |
Withholding tax on stock-based incentive awards | (25,298) |  |  | (14,220) |
Distributions to noncontrolling interest | (61,210) |  |  | (15,983) |
Finance lease obligation payments | (331) |  |  | (296) |
Contingent consideration payment | – |  |  | (60,243) |
Issue costs of debt facility | – |  |  | (20) |
Net cash required by financing activities | (334,271) |  |  | (176,629) |
Effect of exchange rate changes on cash and cash equivalents | 1,249 |  |  | (893) |
Net increase (decrease) in cash and cash equivalents | 16,545 |  |  | (122,608) |
Cash and cash equivalents at beginning of period | 317,074 |  |  | 491,963 |
Cash and cash equivalents at end of period | $ | 333,619 |  |  | $ | 369,355 |

See Notes to Consolidated Financial Statements, page 7.
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Thousands of dollars except number of shares) | 2024 |  | 2023 |  | 2024 |  | 2023
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at June 30, 2024 and 195,100,628 shares at June 30, 2023 |  |  |  |  |  |  |
Balance at beginning and end of period | $ | 195,101 |  |  | $ | 195,101 |  |  | $ | 195,101 |  |  | $ | 195,101 |
Capital in Excess of Par Value |  |  |  |  |  |  |
Balance at beginning of period | 816,815 |  |  | 857,000 |  |  | 880,297 |  |  | 893,578 |
Restricted stock transactions and other | (99) |  |  | (2,321) |  |  | (70,486) |  |  | (42,415) |
Share-based compensation | 10,145 |  |  | 7,272 |  |  | 17,050 |  |  | 10,788 |
Balance at end of period | 826,861 |  |  | 861,951 |  |  | 826,861 |  |  | 861,951 |
Retained Earnings |  |  |  |  |  |  |
Balance at beginning of period | 6,590,308 |  |  | 6,204,217 |  |  | 6,546,079 |  |  | 6,055,498 |
Net income attributable to Murphy | 127,739 |  |  | 98,286 |  |  | 217,741 |  |  | 289,930 |
Cash dividends paid | (45,772) |  |  | (42,942) |  |  | (91,545) |  |  | (85,867) |
Balance at end of period | 6,672,275 |  |  | 6,259,561 |  |  | 6,672,275 |  |  | 6,259,561 |
Accumulated Other Comprehensive Loss |  |  |  |  |  |  |
Balance at beginning of period | (555,735) |  |  | (529,919) |  |  | (521,117) |  |  | (534,686) |
Foreign currency translation (loss) gain, net of income taxes | (16,824) |  |  | 33,083 |  |  | (52,352) |  |  | 36,752 |
Retirement and postretirement benefit plans, net of income taxes | 914 |  |  | 1,053 |  |  | 1,824 |  |  | 2,151 |
Balance at end of period | (571,645) |  |  | (495,783) |  |  | (571,645) |  |  | (495,783) |
Treasury Stock |  |  |  |  |  |  |
Balance at beginning of period | (1,742,498) |  |  | (1,588,841) |  |  | (1,737,566) |  |  | (1,614,717) |
Repurchase of common stock | (56,445) |  |  | – |  |  | (106,494) |  |  | – |
Awarded restricted stock, net of forfeitures | 71 |  |  | 2,319 |  |  | 45,188 |  |  | 28,195 |
Balance at end of period – 43,884,080 shares of common stock in 2024 and 38,945,622 shares of common stock in 2023, at cost | (1,798,872) |  |  | (1,586,522) |  |  | (1,798,872) |  |  | (1,586,522) |
Murphy Shareholders’ Equity | 5,323,720 |  |  | 5,234,308 |  |  | 5,323,720 |  |  | 5,234,308 |
Noncontrolling Interest |  |  |  |  |  |  |
Balance at beginning of period | 188,514 |  |  | 167,110 |  |  | 186,859 |  |  | 154,119 |
Net income attributable to noncontrolling interest | 28,523 |  |  | (6,431) |  |  | 53,179 |  |  | 16,239 |
Distributions to noncontrolling interest owners | (38,209) |  |  | (6,304) |  |  | (61,210) |  |  | (15,983) |
Balance at end of period | 178,828 |  |  | 154,375 |  |  | 178,828 |  |  | 154,375 |
Total Equity | $ | 5,502,548 |  |  | $ | 5,388,683 |  |  | $ | 5,502,548 |  |  | $ | 5,388,683 |

See Notes to Consolidated Financial Statements, page 7.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (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 June 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 June 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 six-month periods ended June 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
Income Tax Disclosures. In December 2023 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 operating 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 significant segments. Murphy is currently evaluating the impact of adopting this standard.
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
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.
The Company’s revenues and other income for the three-month and six-month periods ended June 30, 2024 and 2023 were as follows.

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(Thousands of dollars) |  | 2024 |  | 2023 |  | 2024 |  | 2023
Net crude oil and condensate revenue |  |  |  |  |  |  |
United States - Onshore | $ | 145,955 |  |  | $ | 177,085 |  |  | $ | 288,498 |  |  | $ | 307,166 |
United States - Offshore 1 | 501,692 |  |  | 480,841 |  |  | 982,131 |  |  | 981,151 |
Canada - Onshore | 19,580 |  |  | 19,306 |  |  | 33,453 |  |  | 41,258 |
Canada - Offshore | 43,326 |  |  | 24,871 |  |  | 98,101 |  |  | 41,001 |
Other | 4,307 |  |  | – |  |  | 4,209 |  |  | 3,644 |
Total crude oil and condensate revenue | 714,860 |  |  | 702,103 |  |  | 1,406,392 |  |  | 1,374,220 |
Net natural gas liquids revenue |  |  |  |  |  |  |
United States - Onshore | 7,311 |  |  | 6,540 |  |  | 15,147 |  |  | 14,810 |
United States - Offshore 1 | 9,337 |  |  | 11,541 |  |  | 19,711 |  |  | 26,170 |
Canada - Onshore | 1,595 |  |  | 1,517 |  |  | 3,032 |  |  | 4,980 |
Total natural gas liquids revenue | 18,243 |  |  | 19,598 |  |  | 37,890 |  |  | 45,960 |
Net natural gas revenue |  |  |  |  |  |  |
United States - Onshore | 3,352 |  |  | 4,138 |  |  | 7,628 |  |  | 9,588 |
United States - Offshore 1 | 10,500 |  |  | 14,802 |  |  | 23,389 |  |  | 36,934 |
Canada - Onshore | 50,555 |  |  | 59,195 |  |  | 116,814 |  |  | 129,365 |
Total natural gas revenue | 64,407 |  |  | 78,135 |  |  | 147,831 |  |  | 175,887 |
Revenue from production | 797,510 |  |  | 799,836 |  |  | 1,592,113 |  |  | 1,596,067 |
Sales of purchased natural gas |  |  |  |  |  |  |  |
Canada - Onshore | 3,497 |  |  | 13,014 |  |  | 3,742 |  |  | 56,751 |
Total sales of purchased natural gas | 3,497 |  |  | 13,014 |  |  | 3,742 |  |  | 56,751 |
Total revenue from sales to customers | 801,007 |  |  | 812,850 |  |  | 1,595,855 |  |  | 1,652,818 |
Gain on sale of assets and other income | 1,764 |  |  | 1,738 |  |  | 3,328 |  |  | 3,486 |
Total revenues and other income | $ | 802,771 |  |  | $ | 814,588 |  |  | $ | 1,599,183 |  |  | $ | 1,656,304 |

1 Includes revenue attributable to noncontrolling interest in MP GOM.
Contract Balances and Asset Recognition
As of June 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 $233.2 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
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 June 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, 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 June 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 June 30, 2024
Location |  | Commodity |  | End Date |  | Description |  | Approximate Volumes
U.S. |  | Natural Gas and NGL |  | Q1 2030 |  | Deliveries from dedicated acreage in Eagle Ford |  | As produced
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at USD index pricing |  | 31 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at CAD fixed pricing |  | 124 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at USD fixed pricing |  | 25 MMCFD
Canada |  | Natural Gas |  | Q4 2024 |  | Contracts to sell natural gas at CAD index pricing |  | 28 MMCFD
Canada |  | Natural Gas |  | Q4 2025 |  | Contracts to sell natural gas at USD index pricing |  | 25 MMCFD
Canada |  | Natural Gas |  | Q4 2026 |  | Contracts to sell natural gas at USD index pricing |  | 49 MMCFD
Canada |  | Natural Gas |  | Q4 2027 |  | Contracts to sell natural gas at USD index pricing |  | 30 MMCFD
Canada |  | Natural Gas |  | Q4 2028 |  | Contracts to sell natural gas at USD index pricing |  | 10 MMCFD
Canada |  | NGL |  | Q2 2025 |  | Contracts to sell NGL at CAD index pricing |  | As produced

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 June 30, 2024, the Company had total capitalized drilling costs pending the determination of proved reserves of $43.0 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2024 and 2023.

(Thousands of dollars) | 2024 |  | 2023
Beginning balance at January 1 | $ | 49,118 |  |  | $ | 171,860 |
Additions pending the determination of proved reserves | 20,391 |  |  | 47,733 |
Capitalized exploratory well costs charged to expense | (26,471) |  |  | (26,188) |
Balance at June 30 | $ | 43,038 |  |  | $ | 193,405 |

Capitalized well costs charged to dry hole expense of $26.5 million for the six months ended June 30, 2024 was related to the Hoffe Park #1 (Mississippi Canyon 166) exploratory well in the Gulf of Mexico. Capital additions are mainly for Ocotillo #1 (Mississippi Canyon 40) exploratory well in the Gulf of Mexico. The preceding table excludes well costs of $31.8 million and $70.3 million incurred and expensed directly to dry hole for the six months ended June 30, 2024 and 2023, respectively. In 2024 the amount includes $25.5 million for the Orange #1 (Mississippi Canyon 216) exploration well in the Gulf of Mexico and in 2023 the amount includes $69.2 million related to the Chinook #7 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.

| June 30,
| 2024 |  | 2023
(Thousands of dollars) | Amount |  | No. of Wells |  | No. of Projects |  | Amount |  | No. of Wells |  | No. of Projects
Aging of capitalized well costs: |  |  |  |  |  |  |  |  |  |  |
Zero to one year | $ | 20,545 |  |  | 3 |  |  | 3 |  |  | $ | 8,494 |  |  | 1 |  |  | 1 |
One to two years | – |  |  | – |  |  | – |  |  | 38,497 |  |  | 1 |  |  | 1 |
Two to three years | – |  |  | – |  |  | – |  |  | 2,698 |  |  | 1 |  |  | 1 |
Three years or more | 22,493 |  |  | 3 |  |  | 3 |  |  | 143,716 |  |  | 4 |  |  | 3 |
| $ | 43,038 |  |  | 6 |  |  | 6 |  |  | $ | 193,405 |  |  | 7 |  |  | 6 |

Of the $22.5 million of exploratory well costs capitalized more than one year at June 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 June 30, 2024. There w ere pre-tax impairments of $34.5 million i n the six months ended June 30, 2024 r elated to Calliope field in Mississippi Canyon, in the Gulf of Mexico, where operational issues led to a reserve reduction. There were no impairments in the three and six months en ded June 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 for net cash proceeds of C$139.0 million. No gain or loss was recorded related to this transaction, and the effective date of the transaction was March 1, 2023.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note E – Financing Arrangements and Debt
As of June 30, 2024, the Company had an $800 million revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on November 17, 2027. At June 30, 2024, the Company had no outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2024, the interest rate in effect on borrowings under the RCF would have been 7.69%. At June 30, 2024, the Company was in compliance with all covenants related to the RCF.
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 six months ended June 30, 2024.
The Company also has a 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 through October 15, 2024.
Note F – Other Financial Information
Additional disclosures regarding cash flow activities are provided below.

| Six Months Ended June 30,
(Thousands of dollars) | 2024 |  | 2023
Net (increase) decrease in operating working capital, excluding cash and cash equivalents: |  |  |
(Increase) decrease in accounts receivable | $ | 7,355 |  |  | $ | (18,915) |
(Increase) decrease in inventories | 2,170 |  |  | (8,353) |
Decrease in prepaid expenses | 2,296 |  |  | 8,291 |
Increase (decrease) in accounts payable and accrued liabilities ¹ | (9,689) |  |  | 6,642 |
Increase (decrease) in income taxes payable | (1,006) |  |  | (3,005) |
Net decrease (increase) in noncash working capital | $ | 1,126 |  |  | $ | (15,340) |
Supplementary disclosures: |  |  |
Cash income taxes paid, net of refunds | $ | 3,236 |  |  | $ | 10,904 |
Interest paid, net of amounts capitalized of $7.8 million in 2024 and $6.8 million in 2023 | 38,262 |  |  | 54,305 |
Non-cash investing activities: |  |  |
Asset retirement costs capitalized | $ | 16,175 |  |  | $ | 2,742 |
(Increase) decrease in capital expenditure accrual | (24,780) |  |  | 20,522 |

1 Excludes payable balances relating to contingent consideration for prior acquisitions.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 six-month periods ended June 30, 2024 and 2023 are shown in the following table.

(Thousands of dollars) | June 30, 2024 |  | June 30, 2023
Balance at beginning of year | $ | 914,763 |  |  | $ | 911,653 |
Accretion | 25,827 |  |  | 22,521 |
Liabilities incurred | 14,199 |  |  | 4,805 |
Revisions of previous estimates | 1,995 |  |  | (822) |
Liabilities settled | (2,925) |  |  | (64,978) |
Changes due to translation of foreign currencies | (4,541) |  |  | 2,920 |
Balance at end of period | 949,318 |  |  | 876,099 |
Current portion of liability 1 | (25,622) |  |  | (32,771) |
Noncurrent portion of liability | $ | 923,696 |  |  | $ | 843,328 |

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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note H – Employee and Retiree Benefit Plans
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 six-month periods ended June 30, 2024 and 2023.

| Three Months Ended June 30,
| Pension Benefits |  | Other Postretirement Benefits
(Thousands of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Service cost | $ | 1,706 |  |  | $ | 1,650 |  |  | $ | 135 |  |  | $ | 132 |
Interest cost | 8,393 |  |  | 8,564 |  |  | 782 |  |  | 874 |
Expected return on plan assets | (8,359) |  |  | (8,254) |  |  | – |  |  | – |
Estimated defined contribution provision | 54 |  |  | 54 |  |  | – |  |  | – |
Amortization of prior service cost (credit) | 579 |  |  | 155 |  |  | (133) |  |  | (133) |
Recognized actuarial loss (gain) | 2,361 |  |  | 2,414 |  |  | (812) |  |  | (767) |
Total net periodic benefit expense | $ | 4,734 |  |  | $ | 4,583 |  |  | $ | (28) |  |  | $ | 106 |
| Six Months Ended June 30,
| Pension Benefits |  | Other Postretirement Benefits
(Thousands of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Service cost | $ | 3,412 |  |  | $ | 3,300 |  |  | $ | 270 |  |  | $ | 264 |
Interest cost | 16,784 |  |  | 17,071 |  |  | 1,564 |  |  | 1,748 |
Expected return on plan assets | (16,716) |  |  | (16,448) |  |  | – |  |  | – |
Estimated defined contribution provision | 109 |  |  | 108 |  |  | – |  |  | – |
Amortization of prior service cost (credit) | 1,158 |  |  | 310 |  |  | (266) |  |  | (266) |
Recognized actuarial loss (gain) | 4,721 |  |  | 4,815 |  |  | (1,624) |  |  | (1,548) |
Total net periodic benefit expense | $ | 9,468 |  |  | $ | 9,156 |  |  | $ | (56) |  |  | $ | 198 |

The components of net periodic benefit expense, other than the service cost, are recorded in “Other income (loss)” in the Consolidated Statements of Operations.
During the six-month period ended June 30, 2024, the Company made contributions of $18.9 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 $22.3 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 six months ended June 30, 2024, the Committee granted the following awards from the 2020 Long-Term Plan:

Type of Award |  | Number of Awards Granted |  | Grant Date |  | Grant 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

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 restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
The Company currently has outstanding incentive awards issued to Directors under the 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 six months ended June 30, 2024, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:

Type of Award |  | Number of Awards Granted |  | Grant Date |  | Grant Date Fair Value |  | Valuation 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

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.
In 2017, the Company ceased granting stock options and SARs as a part of the Company’s long-term incentive compensation program. As of June 30, 2024 there were no outstanding stock options or SARs remaining.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

| Six Months Ended June 30,
(Thousands of dollars) | 2024 |  | 2023
Compensation charged against income before tax benefit | $ | 19,987 |  |  | $ | 23,684 |
Related income tax benefit recognized in income | 2,067 |  |  | 3,444 |

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 six-month periods ended June 30, 2024 and 2023. The following table reports the weighted-average shares outstanding used for these computations.

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Weighted-average shares) | 2024 |  | 2023 |  | 2024 |  | 2023
Basic method | 152,153,401 |  |  | 156,126,580 |  |  | 152,408,912 |  |  | 155,976,326 |
Dilutive stock options and restricted stock units | 990,183 |  |  | 1,172,382 |  |  | 1,070,766 |  |  | 1,331,696 |
Diluted method | 153,143,584 |  |  | 157,298,962 |  |  | 153,479,678 |  |  | 157,308,022 |

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 six-month periods ended June 30, 2024 and 2023, the Company’s effective income tax rates were as follows:

| 2024 |  | 2023
Three months ended June 30, | 17.2% |  | 27.4%
Six months ended June 30, | 18.7% |  | 22.4%

The effective tax rate for the three-month period ended June 30, 2024, was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, and a Canada tax credit received. These impacts are partially offset by the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate, and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.
The effective tax rate for the three-month period ended June 30, 2023, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: no tax benefit applied to the pre-tax loss of the noncontrolling interest in MP GOM; U.S. state tax expense; stock-based compensation; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.
The effective tax rate for the six-month period ended June 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM, and a Canada tax credit received. These impacts were partially offset by 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note K – Income Taxes (Continued)
The effective tax rate for the six-month period ended June 30, 2023 was 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 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 June 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.
Commodity Price Risks
During the second quarter of 2024 and 2023, the Company did not have any crude oil derivative contracts.
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 June 30, 2024 and 2023.
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 June 30, 2024 and December 31, 2023, are shown in the following table.

|  | June 30, 2024 |  | December 31, 2023
(Thousands of dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  | Total |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Nonqualified employee savings plan |  | $ | 18,365 |  |  | $ | – |  |  | $ | – |  |  | $ | 18,365 |  |  | $ | 17,785 |  |  | $ | – |  |  | $ | – |  |  | $ | 17,785 |
|  | $ | 18,365 |  |  | $ | – |  |  | $ | – |  |  | $ | 18,365 |  |  | $ | 17,785 |  |  | $ | – |  |  | $ | – |  |  | $ | 17,785 |

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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations.
As of June 30, 2024 and December 31, 2023, there were no outstanding commodity WTI crude oil swaps and collars contracts subject to fair value measurement, nor were there any commodity swaps and collars liabilities.
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 six months ended June 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”.
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 June 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 June 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.

| June 30, |  | December 31,
| 2024 |  | 2023
(Thousands of dollars) | Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Financial liabilities: |  |  |  |  |  |  |
Current and long-term debt | $ | 1,280,049 |  |  | $ | 1,236,039 |  |  | $ | 1,329,075 |  |  | $ | 1,265,185 |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note M – Accumulated Other Comprehensive Loss
The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2023 and June 30, 2024 and the changes during the six-month period ended June 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 | (52,352) |  |  | – |  |  |  |  | (52,352) |
Reclassifications to income ¹ | – |  |  | 1,824 |  |  |  |  | 1,824 |
Net other comprehensive income (loss) | (52,352) |  |  | 1,824 |  |  |  |  | (50,528) |
Balance at June 30, 2024 | $ | (433,984) |  |  | $ | (137,661) |  |  |  |  | $ | (571,645) |

1 Reclassifications before taxes of $2.5 million are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2024. See Note H for additional information. Related income taxes of $0.7 million are included in "Income tax expense” on the Consolidated Statements of Operations for the six-month period ended June 30, 2024.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)
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 are 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 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note O – Common Stock Issued and Outstanding
Activity in the number of shares of common stock issued and outstanding for the six-month periods ended June 30, 2024 and 2023 is shown below.

(Number of shares outstanding) | June 30, 2024 |  | June 30, 2023 |  |
Beginning of period | 152,748,642 |  |  | 155,467,319 |  |  |
Restricted stock awards 1 | 1,102,501 |  |  | 687,687 |  |  |
Treasury shares purchased | (2,634,595) |  |  | – |  |  |
End of period | 151,216,548 |  |  | 156,155,006 |  |  |

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.
On August 4, 2022, the Company’s Board of Directors authorized a share repurchase program of up to $300 million of the Company’s common stock. On October 30, 2023, the Company authorized an increase to the share repurchase program of an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million. 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 six months ended June 30, 2024, the Company repurchased 2.6 million shares of its common stock under the share repurchase program for $105.8 million ($106.5 million including excise taxes and fees). As of June 30, 2024, the Company had $344 million of its common stock remaining available to repurchase under the program.
On August 7, 2024, the Company’s Board of Directors authorized an increase to the share repurchase program of an additional $500 million, bringing the total amount allowed to be repurchased under the program to $1.1 billion. Subsequent to the second quarter of 2024, the Company repurchased 1,142,867 shares of its common stock in open-market transactions for $44.1 million, excluding taxes and fees. As of August 7, 2024 the Company had $800 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 June 30, 2024 |  | Three Months Ended June 30, 2024 |  | Three Months Ended June 30, 2023
(Millions of dollars) |  | External Revenues |  | Income (Loss) |  | External Revenues |  | Income (Loss)
Exploration and production ¹ |  |  |  |  |  |  |  |  |  |
United States 2 |  | $ | 7,222.6 |  |  | $ | 679.5 |  |  | $ | 185.7 |  |  | $ | 696.2 |  |  | $ | 168.9 |
Canada |  | 2,050.5 |  |  | 119.0 |  |  | 8.9 |  |  | 118.3 |  |  | 2.5 |
Other |  | 244.2 |  |  | 4.3 |  |  | (10.1) |  |  | – |  |  | (32.3) |
Total exploration and production |  | 9,517.3 |  |  | 802.8 |  |  | 184.5 |  |  | 814.5 |  |  | 139.1 |
Corporate |  | 375.3 |  |  | – |  |  | (27.7) |  |  | 0.1 |  |  | (46.6) |
Continuing operations |  | 9,892.6 |  |  | 802.8 |  |  | 156.8 |  |  | 814.6 |  |  | 92.5 |
Discontinued operations, net of tax |  | 1.1 |  |  | – |  |  | (0.6) |  |  | – |  |  | (0.6) |
Total |  | $ | 9,893.7 |  |  | $ | 802.8 |  |  | $ | 156.2 |  |  | $ | 814.6 |  |  | $ | 91.9 |
|  |  |  | Six Months Ended June 30, 2024 |  | Six Months Ended June 30, 2023
(Millions of dollars) |  |  |  | External Revenues |  | Income (Loss) |  | External Revenues |  | Income (Loss)
Exploration and production ¹ |  |  |  |  |  |  |  |  |  |
United States 2 |  |  |  | $ | 1,339.1 |  |  | $ | 320.2 |  |  | $ | 1,378.5 |  |  | $ | 394.9 |
Canada |  |  |  | 255.9 |  |  | 28.3 |  |  | 274.1 |  |  | 24.4 |
Other |  |  |  | 4.2 |  |  | (20.9) |  |  | 3.6 |  |  | (37.6) |
Total exploration and production |  |  |  | 1,599.2 |  |  | 327.6 |  |  | 1,656.2 |  |  | 381.7 |
Corporate |  |  |  | – |  |  | (55.2) |  |  | 0.1 |  |  | (75.2) |
Continuing operations |  |  |  | 1,599.2 |  |  | 272.4 |  |  | 1,656.3 |  |  | 306.5 |
Discontinued operations, net of tax |  |  |  | – |  |  | (1.5) |  |  | – |  |  | (0.3) |
Total |  |  |  | $ | 1,599.2 |  |  | $ | 270.9 |  |  | $ | 1,656.3 |  |  | $ | 306.2 |

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 and expand 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 Leases |  | Finance Leases |  | Total
2024 | $ | 158,984 |  |  | $ | 534 |  |  | $ | 159,518 |
2025 | 266,213 |  |  | 1,069 |  |  | 267,282 |
2026 | 111,686 |  |  | 1,069 |  |  | 112,755 |
2027 | 61,053 |  |  | 1,069 |  |  | 62,122 |
2028 | 60,182 |  |  | 1,069 |  |  | 61,251 |
Remaining | 484,971 |  |  | 267 |  |  | 485,238 |
Total future minimum lease payments | 1,143,089 |  |  | 5,077 |  |  | 1,148,166 |
Less imputed interest | (243,266) |  |  | (1,137) |  |  | (244,403) |
Present value of lease liabilities 1 | $ | 899,823 |  |  | $ | 3,940 |  |  | $ | 903,763 |

1 Includes both the current and long-term portion of the lease liabilities.
Lease Term and Discount Rate

| June 30, 2024 |  | December 31, 2023
Weighted average remaining lease term: |  |  |
Operating leases | 8 years |  | 10 years
Finance leases | 5 years |  | 5 years
Weighted average discount rate: |  |  |
Operating leases | 5.7 | % |  | 5.9 | %
Finance leases | 4.7 | % |  | 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 June 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 second quarter of 2024 were as follows:
•Produced 187,847 barrels of oil equivalent per day (including NCI) during the quarter
•Drilled a discovery at the non-operated Ocotillo #1 exploration well in Mississippi Canyon 40 in the Gulf of Mexico
•Maintained quarterly dividend of $0.30 per share or $1.20 per share annualized
•Advanced the capital allocation framework 1:
◦Repurchased $55.9 million ($56.4 million including excise taxes and fees) of common stock, or 1,361,350 shares, at an average price of $41.03 per share
◦Completed the open market repurchase of approximately $50.0 million of long-term debt notes
1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022 and August 8, 2024.
Subsequent to the second quarter of 2024:
•On August 7, 2024 the Company’s Board of Directors authorized an increase to the share repurchase program of an additional $500 million, bringing the total amount allowed to be repurchased under the program to $1.1 billion
•As of August 7, 2024 the Company repurchased $44.1 million ($44.6 million including excise taxes and fees) of common stock, or 1,142,867 shares, and had $800 million of its common stock available to repurchase under the program
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2024, was $156.9 million, an increase of $64.4 million compared to the same period in 2023. Higher net income from continuing operations was largely driven by lower exploration costs ($73.1 million), higher other income ($33.9 million) and lower interest expense on long-term debt ($8.9 million), partially offset by higher lease operating costs ($65.3 million). The decrease in exploration costs were driven primarily by lower dry hole costs related to the Orange #1 (Mississippi Canyon 216) exploration well that encountered non-commercial hydrocarbons in the second quarter of 2024. In the second quarter of 2023, exploration costs included dry hole costs relating to the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico, and previously suspended exploration costs for the Cholula-1EXP well in Mexico. Higher other income related to foreign exchange gains and interest income on several outstanding joint interest receivables and lower interest expense on long-term debt related to debt repayments since the prior period. These were partially offset by increased workover costs in the Gulf of Mexico.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Overview (Continued)
For the three months ended June 30, 2024 total hydrocarbon production was 187,847 barrels of oil equivalent per day, a decrease of 1% compared to the second quarter of 2023. The decrease was principally due to lower production in the U.S., primarily at the Eagle Ford Shale due to a lower number of new wells on production, and in the Gulf of Mexico due to downtime and timing of new wells . Decreases in the U.S. were offset by increases in Canada at both Tupper Montney, due to new wells online, and Terra Nova, which restarted production in late 2023.
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the six months ended June 30, 2024 was $272.4 million, a decrease of $34.1 million compared to the same period of 2023. Lower net income from continuing operations was largely driven by higher lease operating expenses ($99.6 million), higher impairment of assets ($34.5 million), and higher DD&A expense ($15.3 million). Decreases were partially offset by higher other income ($45.6 million), lower exploration expenses ($38.9 million), lower income tax expense ($26.0 million), and lower interest expense on long-term debt ($17.7 million). Higher lease operating expenses related to workover costs at Neidermeyer and were partially offset by lower production handling costs at the King’s Quay floating production facility in the Gulf of Mexico. Impairment costs related to the Calliope field were recorded in the first quarter of 2024. Higher other income related to foreign exchange gains and interest income on outstanding joint interest receivables. Exploration expense in the current period was primarily due to dry hole expenses recorded for the Orange #1 (Mississippi Canyon 216) non-operated exploratory well in the Gulf of Mexico, the previously suspended exploration costs for Hoffe Park #1 (Mississippi Canyon 166), and additional costs related to the Oso #1 (Atwater Valley 138) exploration well in the Gulf of Mexico. The Orange #1 (Mississippi Canyon 216) exploratory well encountered non-commercial hydrocarbons and was classified to dry hole expense in the second quarter of 2024. The Hoffe Park #1 (Mississippi Canyon 166) lease expired in 2024 and there are no plans for additional exploration activities. The Oso #1 (Atwater Valley 138) exploration well encountered non-commercial hydrocarbons in the fourth quarter of 2023 and operations finished in the first quarter of 2024. Lower income tax expense was driven by lower net income. Lower interest expense is driven by overall lower debt levels.
For the six months ended June 30, 2024 total hydrocarbon production was 182,259 barrels of oil equivalent per day, a decrease of 2% 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 timing of new wells, and in the Eagle Ford Shale due to a lower number of new wells on production in the current period. Decreases in the U.S. were substantially offset by increases in Canada at both Tupper Montney due to new wells online, and 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)
Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below.

| Income (Loss)
| Three Months Ended June 30, |  | Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Exploration and production |  |  |  |  |  |  |
United States | $ | 185.7 |  |  | $ | 168.9 |  |  | $ | 320.2 |  |  | $ | 394.9 |
Canada | 8.9 |  |  | 2.5 |  |  | 28.3 |  |  | 24.4 |
Other | (10.1) |  |  | (32.3) |  |  | (20.9) |  |  | (37.6) |
Total exploration and production | 184.5 |  |  | 139.1 |  |  | 327.6 |  |  | 381.7 |
Corporate | (27.7) |  |  | (46.6) |  |  | (55.2) |  |  | (75.2) |
Income from continuing operations | 156.8 |  |  | 92.5 |  |  | 272.4 |  |  | 306.5 |
Discontinued operations ¹ | (0.6) |  |  | (0.6) |  |  | (1.5) |  |  | (0.3) |
Net income including noncontrolling interest | 156.2 |  |  | 91.9 |  |  | 270.9 |  |  | 306.2 |
Net income (loss) attributable to noncontrolling interest | 28.5 |  |  | (6.4) |  |  | 53.2 |  |  | 16.3 |
Net income attributable to Murphy | $ | 127.7 |  |  | $ | 98.3 |  |  | $ | 217.7 |  |  | $ | 289.9 |

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 June 30, |  | Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Revenues and other income |  |  |  |  |  |  |
Revenue from production | $ | 797.5 |  |  | $ | 799.8 |  |  | $ | 1,592.1 |  |  | $ | 1,596.1 |
Sales of purchased natural gas | 3.5 |  |  | 13.0 |  |  | 3.7 |  |  | 56.8 |
Other income | 1.8 |  |  | 1.7 |  |  | 3.4 |  |  | 3.2 |
Total revenues and other income | 802.8 |  |  | 814.5 |  |  | 1,599.2 |  |  | 1,656.1 |
Cost and Expenses |  |  |  |  |  |  |
Lease operating expenses | 259.6 |  |  | 194.1 |  |  | 493.9 |  |  | 394.2 |
Severance and ad valorem taxes | 10.4 |  |  | 12.8 |  |  | 20.5 |  |  | 24.2 |
Transportation, gathering and processing | 53.5 |  |  | 60.0 |  |  | 110.0 |  |  | 113.8 |
Costs of purchased natural gas | 2.9 |  |  | 9.7 |  |  | 3.1 |  |  | 41.9 |
Depreciation, depletion and amortization | 212.9 |  |  | 213.0 |  |  | 421.2 |  |  | 405.8 |
Impairments of assets | – |  |  | – |  |  | 34.5 |  |  | – |
Accretion of asset retirement obligations | 13.1 |  |  | 11.3 |  |  | 25.8 |  |  | 22.5 |
Total exploration expenses | 42.8 |  |  | 115.8 |  |  | 87.2 |  |  | 126.0 |
Selling and general expenses | 2.9 |  |  | 5.4 |  |  | 9.0 |  |  | 14.4 |
Other | (20.2) |  |  | 7.3 |  |  | (11.4) |  |  | 21.0 |
Results of operations before taxes | 224.9 |  |  | 185.1 |  |  | 405.4 |  |  | 492.3 |
Income tax provisions | 40.4 |  |  | 46.0 |  |  | 77.8 |  |  | 110.6 |
Results of operations (excluding Corporate segment) 1 | $ | 184.5 |  |  | $ | 139.1 |  |  | $ | 327.6 |  |  | $ | 381.7 |

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 six-month periods ended June 30, 2024 and 2023.

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Weighted average sales prices) | 2024 |  | 2023 |  | 2024 |  | 2023
Crude oil and condensate – dollars per barrel |  |  |  |  |  |  |
United States - Onshore | $ | 80.71 |  |  | $ | 72.39 |  |  | $ | 78.76 |  |  | $ | 73.47 |
United States - Offshore 1 | 81.67 |  |  | 73.82 |  |  | 79.61 |  |  | 73.54 |
Canada - Onshore 2 | 72.25 |  |  | 68.50 |  |  | 70.24 |  |  | 71.46 |
Canada - Offshore 2 | 84.34 |  |  | 80.14 |  |  | 85.25 |  |  | 79.26 |
Other 2 | 100.92 |  |  | – |  |  | 96.43 |  |  | 89.05 |
Natural gas liquids – dollars per barrel |  |  |  |  |  |  |
United States - Onshore | 19.48 |  |  | 16.60 |  |  | 20.08 |  |  | 19.28 |
United States - Offshore 1 | 22.77 |  |  | 20.16 |  |  | 23.56 |  |  | 22.89 |
Canada - Onshore 2 | 35.46 |  |  | 29.90 |  |  | 35.16 |  |  | 39.82 |
Natural gas – dollars per thousand cubic feet |  |  |  |  |  |  |
United States - Onshore | 1.59 |  |  | 1.88 |  |  | 1.77 |  |  | 2.19 |
United States - Offshore 1 | 2.00 |  |  | 2.33 |  |  | 2.32 |  |  | 2.81 |
Canada - Onshore 2 | 1.37 |  |  | 1.85 |  |  | 1.68 |  |  | 2.17 |

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 six-month periods ended June 30, 2024 and 2023.

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Average price for the period) | 2024 |  | 2023 |  | 2024 |  | 2023
Oil and NGLs |  |  |  |  |  |  |
WTI ($/BBL) | $ | 80.57 |  |  | $ | 73.78 |  |  | $ | 78.77 |  |  | $ | 74.96 |
Natural gas |  |  |  |  |  |  |
NYMEX ($/MMBTU) | 2.04 |  |  | 2.12 |  |  | 2.23 |  |  | 2.39 |
AECO (C$/MCF) | 1.18 |  |  | 2.45 |  |  | 1.84 |  |  | 2.83 |

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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 six-month periods ended June 30, 2024 and 2023. For further discussion on volumes, please see “Revenues from Production” section on page 29.

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
(Barrels per day unless otherwise noted) | 2024 |  | 2023 |  | 2024 |  | 2023
Net crude oil and condensate |  |  |  |  |  |  |
United States - Onshore | 19,873 |  |  | 26,880 |  |  | 20,127 |  |  | 23,100 |
United States - Offshore 1 | 66,818 |  |  | 72,022 |  |  | 66,448 |  |  | 73,850 |
Canada - Onshore | 2,978 |  |  | 3,097 |  |  | 2,617 |  |  | 3,190 |
Canada - Offshore | 7,506 |  |  | 2,913 |  |  | 6,885 |  |  | 2,687 |
Other | 245 |  |  | 212 |  |  | 245 |  |  | 240 |
Total net crude oil and condensate | 97,420 |  |  | 105,124 |  |  | 96,322 |  |  | 103,067 |
Net natural gas liquids |  |  |  |  |  |  |
United States - Onshore | 4,125 |  |  | 4,328 |  |  | 4,145 |  |  | 4,243 |
United States - Offshore 1 | 4,505 |  |  | 6,291 |  |  | 4,596 |  |  | 6,316 |
Canada - Onshore | 494 |  |  | 558 |  |  | 474 |  |  | 691 |
Total net natural gas liquids | 9,124 |  |  | 11,177 |  |  | 9,215 |  |  | 11,250 |
Net natural gas – thousands of cubic feet per day |  |  |  |  |  |  |
United States - Onshore | 23,197 |  |  | 24,195 |  |  | 23,714 |  |  | 24,178 |
United States - Offshore 1 | 57,762 |  |  | 69,904 |  |  | 55,462 |  |  | 72,539 |
Canada - Onshore | 406,856 |  |  | 352,265 |  |  | 381,155 |  |  | 328,878 |
Total net natural gas | 487,815 |  |  | 446,364 |  |  | 460,331 |  |  | 425,595 |
Total net hydrocarbons - including NCI 2,3 | 187,847 |  |  | 190,695 |  |  | 182,259 |  |  | 185,250 |
Noncontrolling interest |  |  |  |  |  |  |
Net crude oil and condensate – barrels per day | (6,717) |  |  | (5,949) |  |  | (6,608) |  |  | (6,279) |
Net natural gas liquids – barrels per day | (217) |  |  | (204) |  |  | (214) |  |  | (218) |
Net natural gas – thousands of cubic feet per day | (2,003) |  |  | (1,751) |  |  | (2,039) |  |  | (2,051) |
Total noncontrolling interest 2,3 | (7,268) |  |  | (6,445) |  |  | (7,162) |  |  | (6,839) |
Total net hydrocarbons - excluding NCI 2,3 | 180,579 |  |  | 184,250 |  |  | 175,097 |  |  | 178,411 |

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)
Revenues from Production
The Company’s production revenues by country and product were as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Revenues from production |  |  |  |  |  |  |
United States - Oil | $ | 647.6 |  |  | $ | 657.8 |  |  | $ | 1,270.6 |  |  | $ | 1,288.3 |
United States - Natural gas liquids | 16.6 |  |  | 18.1 |  |  | 34.9 |  |  | 41.0 |
United States - Natural gas | 13.9 |  |  | 18.9 |  |  | 31.0 |  |  | 46.5 |
Canada - Oil | 62.9 |  |  | 44.1 |  |  | 131.6 |  |  | 82.2 |
Canada - Natural gas liquids | 1.6 |  |  | 1.6 |  |  | 3.0 |  |  | 5.0 |
Canada - Natural gas | 50.6 |  |  | 59.2 |  |  | 116.8 |  |  | 129.4 |
Other - Oil | 4.3 |  |  | 0.1 |  |  | 4.2 |  |  | 3.7 |
Total revenue from production | $ | 797.5 |  |  | $ | 799.8 |  |  | $ | 1,592.1 |  |  | $ | 1,596.1 |

Revenues from production for the three months ended June 30, 2024 decreased $2.3 million compared to the same period in 2023. Lower revenue was driven by increased workovers, downtime and timing of wells in the Gulf of Mexico, fewer wells brought online in the Eagle Ford Shale and lower realized natural gas prices in Tupper Montney. These effects were partially offset by increased production due to prior period downtime and improved well performance in the Gulf of Mexico, the Terra Nova field restarting production in the fourth quarter of 2023, new wells online at Tupper Montney, and higher oil prices.
Revenues from production for the six months ended June 30, 2024 decreased $4.0 million compared to the same period in 2023. Lower revenues were primarily related to workovers and downtime 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 new wells online at Tupper Montney, restarting production 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 June 30, |  | Six Months Ended June 30,
|  | (Millions of dollars) |  | (Dollars per equivalent barrel) |  | (Millions of dollars) |  | (Dollars per equivalent barrel)
|  | 2024 |  | 2023 |  | 2024 |  | 2023 |  | 2024 |  | 2023 |  | 2024 |  | 2023
Lease operating expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States - Onshore |  | $ | 37.0 |  |  | $ | 36.7 |  |  | $ | 14.61 |  |  | $ | 11.45 |  |  | $ | 72.7 |  |  | $ | 74.0 |  |  | $ | 14.14 |  |  | $ | 13.03 |
United States - Offshore |  | 175.2 |  |  | 120.0 |  |  | 23.58 |  |  | 14.72 |  |  | 326.2 |  |  | 245.2 |  |  | 21.96 |  |  | 14.71 |
Canada - Onshore |  | 35.3 |  |  | 34.1 |  |  | 5.43 |  |  | 6.01 |  |  | 66.2 |  |  | 67.8 |  |  | 5.46 |  |  | 6.38 |
Canada - Offshore |  | 11.6 |  |  | 3.4 |  |  | 22.60 |  |  | 10.96 |  |  | 28.1 |  |  | 6.5 |  |  | 24.43 |  |  | 12.60 |
Other |  | 0.5 |  |  | 0.1 |  |  | 12.26 |  |  | – |  |  | 0.7 |  |  | 0.7 |  |  | 16.10 |  |  | 17.51 |
Total lease operating expenses |  | $ | 259.6 |  |  | $ | 194.3 |  |  | $ | 15.27 |  |  | $ | 11.21 |  |  | $ | 493.9 |  |  | $ | 394.2 |  |  | $ | 14.83 |  |  | $ | 11.76 |
TGP expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States - Onshore |  | 2.4 |  |  | 2.7 |  |  | 0.93 |  |  | 0.80 |  |  | 5.0 |  |  | 6.8 |  |  | 0.99 |  |  | 1.19 |
United States - Offshore |  | 31.8 |  |  | 37.2 |  |  | 4.29 |  |  | 4.57 |  |  | 65.8 |  |  | 70.5 |  |  | 4.43 |  |  | 4.23 |
Canada - Onshore |  | 18.8 |  |  | 19.1 |  |  | 2.89 |  |  | 3.37 |  |  | 36.7 |  |  | 34.4 |  |  | 3.03 |  |  | 3.24 |
Canada - Offshore |  | 0.5 |  |  | 1.0 |  |  | 1.01 |  |  | 3.08 |  |  | 2.5 |  |  | 2.1 |  |  | 2.13 |  |  | 4.08 |
Total TGP expenses |  | $ | 53.5 |  |  | $ | 60.0 |  |  | $ | 3.14 |  |  | $ | 3.45 |  |  | $ | 110.0 |  |  | $ | 113.8 |  |  | $ | 3.30 |  |  | $ | 3.39 |

For the three months ended June 30, 2024 lease operating expenses increased by $65.3 million and TGP expenses decreased by $6.5 million, compared to the same period in 2023. Higher lease operating expenses were due to workover activity at the Neidermeyer field in the Gulf of Mexico, higher production at Terra nova, and were partially offset by lower production handling 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 six months ended June 30, 2024, lease operating expenses increased by $99.7 million and TGP expenses decreased by $3.8 million, compared to the same period in 2023. Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico and higher production at Terra Nova. 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 June 30, |  | Six Months Ended June 30,
|  | (Millions of dollars) |  | (Dollars per equivalent barrel) |  | (Millions of dollars) |  | (Dollars per equivalent barrel)
|  | 2024 |  | 2023 |  | 2024 |  | 2023 |  | 2024 |  | 2023 |  | 2024 |  | 2023
DD&A expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States - Onshore |  | $ | 75.1 |  |  | $ | 84.8 |  |  | $ | 29.64 |  |  | $ | 26.44 |  |  | $ | 149.2 |  |  | $ | 149.3 |  |  | $ | 29.04 |  |  | $ | 26.30 |
United States - Offshore |  | 99.9 |  |  | 93.2 |  |  | 13.44 |  |  | 11.44 |  |  | 199.8 |  |  | 188.9 |  |  | 13.45 |  |  | 11.33 |
Canada - Onshore |  | 30.8 |  |  | 32.1 |  |  | 4.76 |  |  | 5.65 |  |  | 59.0 |  |  | 61.8 |  |  | 4.86 |  |  | 5.82 |
Canada - Offshore |  | 6.2 |  |  | 2.9 |  |  | 12.00 |  |  | 9.48 |  |  | 12.3 |  |  | 4.9 |  |  | 10.71 |  |  | 9.40 |
Other |  | 0.9 |  |  | – |  |  | 20.69 |  |  | – |  |  | 0.9 |  |  | 0.9 |  |  | 20.68 |  |  | 21.75 |
Total DD&A expense |  | $ | 212.9 |  |  | $ | 213.0 |  |  | $ | 12.52 |  |  | $ | 12.28 |  |  | $ | 421.2 |  |  | $ | 405.8 |  |  | $ | 12.64 |  |  | $ | 12.10 |

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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 June 30, 2024 decreased by $0.1 million, compared to the same period in 2023. The decrease is primarily due to lower production volumes in U.S. Offshore and Onshore, offset by increased rates in the Gulf of Mexico, and higher production volumes in Canada Offshore and Onshore.
DD&A expense for the six months ended June 30, 2024 increased by $15.4 million, compared to the same period in 2023. Higher DD&A expense from U.S. E&P resulted from higher rates in the Gulf of Mexico, partially offset by lower production. Higher DD&A expense for Canada Offshore and Onshore was primarily the result of increased production volumes.
Impairment of Assets
For the three months ended June 30, 2024, there were no impairments. For the six months ended June 30, 2024, the Company impaired assets for $34.5 million related to Calliope field in Mississippi Canyon 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 six months ended June 30, 2023.
Exploration Expenses
The Company’s exploration expenses were as follows:

| Three Months Ended June 30, |  | Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Exploration expenses |  |  |  |  |  |  |
Dry holes and previously suspended exploration costs | $ | 25.9 |  |  | $ | 95.6 |  |  | $ | 58.3 |  |  | $ | 96.5 |
Geological and geophysical | 8.2 |  |  | 10.5 |  |  | 9.6 |  |  | 11.3 |
Other exploration | 5.7 |  |  | 7.0 |  |  | 13.5 |  |  | 12.8 |
Undeveloped lease amortization | 3.0 |  |  | 2.7 |  |  | 5.8 |  |  | 5.4 |
Total exploration expenses | $ | 42.8 |  |  | $ | 115.8 |  |  | $ | 87.2 |  |  | $ | 126.0 |

Exploration expenses for the three months ended June 30, 2024 decreased by $73.0 million compared to the prior year, primarily the result of lower dry hole costs in the current period. Dry hole costs in the current period represented costs associated with the Orange #1 (Mississippi Canyon 216) non-operated exploration well in the U.S. Gulf of Mexico, that encountered non-commercial hydrocarbons in the second quarter of 2024. In the second quarter of 2023, we recorded expenses related to previously suspended exploration costs at the Cholula-1EXP well in Mexico, as well as dry hole costs related to Chinook #7 (Walker Ridge 425) exploration well in U.S. Gulf of Mexico.
Exploration expenses for the six months ended June 30, 2024 decreased by $38.8 million compared to the same period in 2023. In the current period, dry hole costs were recorded for 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 six months ended June 30, 2024 decreased by $27.5 million and $32.4 million, respectively, compared to the same periods in 2023. This decrease was due to a combination of interest income received, and a favorable 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 six months ended June 30, 2024 decreased by $5.6 million and $32.8 million, respectively, compared to the same periods in 2023. Lower income taxes for each period, respectively, were primarily the result of Canada tax credits received in the current quarter, and lower year-to-date pre-tax income.
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 $27.7 million for the three months ended June 30, 2024, a favorable variance of $18.9 million compared to the same period of 2023. The favorable variance was primarily due to foreign exchange gains ($13.2 million) and decreased interest expense ($8.8 million), partially offset by lower income tax benefits ($3.5 million). Lower interest expense for the current period was primarily due to lower overall debt levels. Lower income tax benefit was the result of lower pre-tax losses.
Corporate activities reported a loss of $55.2 million for the six months ended June 30, 2024, a favorable variance of $20.0 million compared to the same period of 2023. The favorable variance was primarily due to foreign exchange gains ($24.1 million) and lower interest expense ($17.8 million), partially offset by increased selling and general expense ($15.7 million) and lower income tax benefits ($6.9 million). Lower interest expense for the current period was primarily due to lower overall debt levels. Higher selling and general expenses for the six months ended June 30, 2024 were primarily the result of the 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 its senior unsecured RCF. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.
Cash Flows
The following table presents the Company’s cash flows for the periods presented:

| Six Months Ended June 30,
(Thousands of dollars) | 2024 |  | 2023
Net cash provided by (required by): |  |  |
Net cash provided by continuing operations activities | $ | 866.4 |  |  | $ | 749.7 |
Net cash required by investing activities | (516.9) |  |  | (694.8) |
Net cash required by financing activities | (334.3) |  |  | (176.6) |
Effect of exchange rate changes on cash and cash equivalents | 1.3 |  |  | (0.9) |
Net increase (decrease) in cash and cash equivalents | $ | 16.5 |  |  | $ | (122.6) |

Cash Provided by Continuing Operations Activities
Net cash provided by continuing operations activities for the six months ended June 30, 2024 was $116.7 million higher compared to the same period in 2023. The increase was primarily attributable to no contingent consideration payments related to prior Gulf of Mexico acquisitions in 2024 (2023: $139.6 million), lower spend on abandonments in 2024 ($62.0 million), and higher other income ($19.3 million).These increases were partially offset by increased lease operating expenses ($99.6 million).
Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows; amounts considered as financing activities are those
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
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 six months ended June 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 six months ended June 30, 2024 was $177.9 million lower compared to the same period in 2023. The decrease was due to lower property additions and dry hole costs.
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

| Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023
Property additions and dry hole costs per cash flow statements | $ | 516.9 |  |  | $ | 694.8 |
Geophysical and other exploration expenses | 19.0 |  |  | 20.0 |
Capital expenditure accrual changes and other | 28.8 |  |  | (16.5) |
Total capital expenditures | $ | 564.7 |  |  | $ | 698.3 |

Total accrual basis capital expenditures are shown below.

| Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023
Capital Expenditures |  |  |
Exploration and production | $ | 556.3 |  |  | $ | 688.4 |
Corporate | 8.4 |  |  | 9.9 |
Total capital expenditures | $ | 564.7 |  |  | $ | 698.3 |

Lower capital expenditures in the six months ended June 30, 2024 compared to the same period of 2023 was primarily attributable to lower exploration expenditures in the Gulf of Mexico, and lower development expenditures at Eagle Ford Shale, 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 ($164.7 million), at Tupper Montney ($71.2 million) and Kaybob Duvernay ($24.1 million) in Canada, and at the Khaleesi, Mormont, Samurai, Lucius and St. Malo fields in the Gulf of Mexico ($182.9 million). Other international field development activities were ($15.5 million), and total exploration costs were $84.1 million.
Total exploration costs in 2024 were in the Gulf of Mexico for the Orange #1 (Mississippi Canyon 216) exploration well, that encountered non-commercial hydrocarbons, the Ocotillo #1 (Mississippi Canyon 40) exploration well, and additional costs related to Oso #1 (Atwater Valley 138) exploration well, which encountered non-commercial hydrocarbons in the fourth quarter of 2023 and finished operations in the first quarter of 2024.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Cash Required by Financing Activities
Net cash required by financing activities for the six months ended June 30, 2024 increased by $157.7 million compared to the same period in 2023. In 2024, the cash used in financing activities was principally for the repurchase of common shares ($105.9 million), excluding accrued excise tax), cash dividends to shareholders of $0.60 per share ($91.5 million), withholding tax on stock-based incentive awards ($25.3 million), distributions to the noncontrolling interest in the Gulf of Mexico ($61.2 million), and debt repurchases of $50.0 million. In 2023, there were cash dividends to shareholders $85.9 million, withholding tax on stock-based incentive awards ($14.2 million), distributions to the noncontrolling interest in the Gulf of Mexico ($16.0 million), and contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Operating Activities” section.
Liquidity
At June 30, 2024 the Company had approximately $1.1 billion of liquidity consisting of $333.6 million in cash and cash equivalents and $796.3 million available on its committed senior unsecured RCF with a major banking consortium.
The Company’s $800 million senior unsecured RCF expires in November 2027 and as of June 30, 2024 the Company had no outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the facility. At June 30, 2024 the interest rate in effect on borrowings under the facility would have been 7.69%. At June 30, 2024 the Company was in compliance with all covenants related to the RCF.
Cash and invested cash are maintained in several operating locations outside the U.S. As of June 30, 2024 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $67.8 million, the majority of which was held in Canada ($36.3 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) | June 30, 2024 |  | December 31, 2023
Working capital |  |  |
Total current assets | $ | 757.4 |  |  | $ | 752.2 |
Total current liabilities | 927.6 |  |  | 846.5 |
Net working capital liability | $ | (170.2) |  |  | $ | (94.3) |

As of June 30, 2024 net working capital decreased by $75.9 million compared to December 31, 2023. The decrease was primarily attributable to higher accounts payable ($60.9 million) and higher operating lease liabilities ($46.9 million). The decrease was partially offset by lower other accrued liabilities ($26.1 million) and a higher cash balance ($16.5 million).
Higher operating lease liabilities are primarily attributable to the current portion of lease extensions recorded during the period related to a drill ship in the U.S. Gulf of Mexico (See Note Q for additional detail). Higher accounts payable were primarily due to workover activity in the U.S. Gulf of Mexico, and other timing of cash payments.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Capital Employed
A summary of capital employed at June 30, 2024 and December 31, 2023 follows.

| June 30, 2024 |  | December 31, 2023
(Millions of dollars) | Amount |  | % |  | Amount |  | %
Capital employed |  |  |  |  |  |  |
Long-term debt | $ | 1,279.3 |  |  | 19.4 | % |  | $ | 1,328.3 |  |  | 19.9 | %
Murphy shareholders' equity | 5,323.7 |  |  | 80.6 | % |  | 5,362.8 |  |  | 80.1 | %
Total capital employed | $ | 6,603.0 |  |  | 100.0 | % |  | $ | 6,691.1 |  |  | 100.0 | %

At June 30, 2024 long-term debt of $1,279.3 million decreased by $49.0 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 7.8 years and a weighted average coupon of 6.2%.
Murphy shareholders’ equity decreased by $39.1 million in 2024 primarily due to shares repurchased ($106.5 million, including excise tax), cash dividends paid ($91.5 million) and unrealized foreign currency translation losses ($52.4 million), partially offset by net income earned ($217.7 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 June 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 June 30, |  | Six Months Ended June 30,
(Millions of dollars, except per share amounts) | 2024 |  | 2023 |  | 2024 |  | 2023
Net income attributable to Murphy (GAAP) 1 | $ | 127.7 |  |  | $ | 98.3 |  |  | $ | 217.7 |  |  | $ | 289.9 |
Discontinued operations loss | 0.6 |  |  | 0.6 |  |  | 1.5 |  |  | 0.3 |
Net income from continuing operations attributable to Murphy | 128.3 |  |  | 98.9 |  |  | 219.2 |  |  | 290.2 |
Adjustments: |  |  |  |  |  |  |
Impairment of assets | – |  |  | – |  |  | 34.5 |  |  | – |
Write-off of previously suspended exploration well | – |  |  | 17.1 |  |  | 26.1 |  |  | 17.1 |
Foreign exchange (gain) loss | (5.5) |  |  | 7.9 |  |  | (16.0) |  |  | 8.3 |
Mark-to-market loss on contingent consideration | – |  |  | 3.2 |  |  | – |  |  | 7.1 |
Total adjustments, before taxes | (5.5) |  |  | 28.2 |  |  | 44.6 |  |  | 32.5 |
Income tax benefit related to adjustments | 1.4 |  |  | (2.7) |  |  | (8.8) |  |  | (3.6) |
Total adjustments after taxes | (4.1) |  |  | 25.5 |  |  | 35.8 |  |  | 28.9 |
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 124.2 |  |  | $ | 124.4 |  |  | $ | 255.0 |  |  | $ | 319.1 |
Net income from continuing operations per average diluted share (GAAP) | $ | 0.83 |  |  | 0.62 |  |  | $ | 1.43 |  |  | 1.84 |
Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 0.81 |  |  | 0.79 |  |  | $ | 1.66 |  |  | 2.03 |

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 June 30, |  | Six Months Ended June 30,
(Millions of dollars) | 2024 |  | 2023 |  | 2024 |  | 2023
Net income attributable to Murphy (GAAP) 1 | $ | 127.7 |  |  | $ | 98.3 |  |  | $ | 217.7 |  |  | $ | 289.9 |
Income tax expense | 32.6 |  |  | 34.9 |  |  | 62.7 |  |  | 88.7 |
Interest expense, net | 21.0 |  |  | 29.9 |  |  | 41.0 |  |  | 58.7 |
Depreciation, depletion and amortization expense 1 | 207.4 |  |  | 210.1 |  |  | 410.1 |  |  | 399.3 |
EBITDA attributable to Murphy (Non-GAAP) | 388.7 |  |  | 373.2 |  |  | 731.5 |  |  | 836.6 |
Impairment of asset | – |  |  | – |  |  | 34.5 |  |  | – |
Write-off of previously suspended exploration well | – |  |  | 17.1 |  |  | 26.1 |  |  | 17.1 |
Accretion of asset retirement obligations 1 | 11.7 |  |  | 10.1 |  |  | 23.1 |  |  | 20.0 |
Foreign exchange (gain) loss | (5.4) |  |  | 7.9 |  |  | (15.9) |  |  | 8.3 |
Mark-to-market loss on contingent consideration | – |  |  | 3.2 |  |  | – |  |  | 7.1 |
Discontinued operations loss | 0.6 |  |  | 0.6 |  |  | 1.5 |  |  | 0.3 |
Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 395.6 |  |  | $ | 412.1 |  |  | $ | 800.8 |  |  | $ | 889.4 |

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, higher average crude oil price during the second quarter of 2024, and lower average natural gas pricing compared to same period in 2023 directly impacted the Company’s product sales revenue.
As of close on August 6, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:

|  | 2024 |  | 2025
WTI ($/BBL) |  | 72.10 |  | 69.17
NYMEX ($/MMBTU) |  | 2.45 |  | 3.16
AECO (US$ Equivalent/MCF) |  | 1.19 |  | 1.90

Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.
We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash flows. For the third 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. In October 2023 and August 2024, the Company’s Board of Directors authorized an aggregate of $800 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $1.1 billion. On August 7, 2024 the Company’s Board of Directors approved a revision to the Capital Allocation Framework to enable the Company to move to the next phase (“Murphy 3.0”). Beginning in the third quarter of 2024, Murphy will allocate a minimum of 50 percent of adjusted free cash flow to shareholder returns, primarily through share buybacks. The remainder of adjusted free cash flow will be allocated to the balance sheet. Murphy continues to be committed to maintaining a $1.0 billion total long-term debt goal.
Subsequent to the second quarter of 2024, the Company repurchased 1,142,867 shares of its common stock in open-market transactions for $44.1 million, excluding taxes and fees. As of August 7, 2024, the Company had $800 million of its common stock remaining available to repurchase under the program.
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)
As of August 6, 2024, the Company has entered into forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

|  |  |  |  |  | Volumes (MMcf/d) |  | Price/MCF |  | Remaining Period
Area |  | Commodity |  | Type |  |  |  | Start Date |  | End Date
Canada |  | Natural Gas |  | Fixed price forward sales |  | 162 |  |  | C$2.39 |  | 7/1/2024 |  | 12/31/2024
Canada |  | Natural Gas |  | Fixed price forward sales |  | 28 |  |  | C$2.76 |  | 1/1/2025 |  | 12/31/2025
Canada |  | Natural Gas |  | Fixed price forward sales |  | 50 |  |  | C$3.03 |  | 1/1/2026 |  | 12/31/2026
Canada |  | Natural Gas |  | Fixed price forward sales |  | 25 |  |  | US$1.98 |  | 7/1/2024 |  | 10/31/2024
Canada |  | Natural Gas |  | Fixed price forward sales |  | 15 |  |  | US$1.98 |  | 11/1/2024 |  | 12/31/2024

Forward-Looking Statements
This Form 10-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 41 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 no derivative commodity contracts in place at June 30, 2024.
There were no derivative foreign exchange contracts in place at June 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 June 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. In March 2024, the SEC finalized its climate disclosure rule, SEC Release No. 34-99678, The Enhancement and Standardization of Climate-Related Disclosures for Investor s, which requires registrants to provide certain climate-related information in their annual reports. In April 2024, the SEC stayed the climate disclosure rule pending judicial review. The Company has not identified any additional risk factors not previously disclosed in its 2023 Form 10-K report or noted above.
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 second quarter 2024.

Period |  | Total Number of Shares Purchased |  | Average Price Paid Per Share 1 |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs 4 |  | Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs 2,3,4 (in thousands)
April 1 through April 30, 2024 |  | – |  |  | $ | – |  |  | – |  |  | $ | 400,000 |
May 1 through May 31, 2024 |  | 590,034 |  |  | $ | 42.37 |  |  | 590,034 |  |  | $ | 375,000 |
June 1 through June, 30, 2024 |  | 771,316 |  |  | $ | 40.01 |  |  | 771,316 |  |  | $ | 344,000 |

1 Amounts exclude 1% excise tax and fees on share repurchases.
2 In August 2022 and October 2023, the Board authorized an initial share repurchase program of up to $600 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. On August 7, 2024, the Company’s Board of Directors authorized an increase to the share repurchase program of an additional $500 million, bringing the total amount allowed to be repurchased under the program to $1.1 billion. In addition, the Company’s Board of Directors approved a revision to the Capital Allocation Framework to enable the Company to move to the next phase (“Murphy 3.0”). Beginning in the third quarter of 2024, Murphy will allocate a minimum of 50 percent of adjusted free cash flow to shareholder returns, primarily through share buybacks. The remainder of adjusted free cash flow will be allocated to the balance sheet.
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 second quarter of 2024, the Company has repurchased 6,045,753 shares of its common stock in open-market transactions for $255.8 million, excluding taxes and fees.
4 Subsequent to the second quarter of 2024, the Company repurchased 1,142,867 shares of its common stock in open-market transactions for $44.1 million, excluding taxes and fees. As of August 7, 2024 the Company had $800 million of its common stock remaining available to repurchase under the program.
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ITEM 5. OTHER INFORMATION
(a)On August 6, 2024, in connection with his recent promotion to President and Chief Operating Officer, the Company entered into an amendment to the Severance Protection Agreement between the Company and Eric M. Hambly (the “Severance Protection Agreement Amendment”). Pursuant to the Severance Protection Agreement Amendment (i) Mr. Hambly’s severance multiplier has increased from 2 times to 3 times and (ii) the length of Mr. Hambly’s continued life, accident and health insurance coverage has increased from 30-months to 36-months. The terms of Mr. Hambly’s agreement, which were described in the section titled “2023 Potential Payments Upon Termination or Change in Control Table” of the Company’s definitive proxy statement filed with the Securities and Exchange Commission on March 21, 2024, otherwise remained unchanged.
The foregoing description of the Severance Protection Agreement, as amended, does not purport to be complete and is qualified in its entirety by reference to the form of Severance Protection Agreement, a copy of which is filed as an exhibit to this Quarterly Report.
(b)Not used.
(c)During the three months ended June 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 44 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)

August 8, 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. |  |  |
1 0.36 |  | Severance Protection Agreement dated as of August 7, 2013 between Murphy Oil Corporation and Roger W. Jenkins (incorporated by referenc e to Exhibit 10.1 to Form 8-K of Registran t filed on Aug ust 9, 20 13) |
1 0.3 7 |  | Amendment to Severance Protection Agreement dated as of August 7, 2013, between Murphy Oil Corporation and Roger W. Jenkins (incorporated by reference to Exhibit 10.1 to Form 10-Q of Registrant filed on May 2, 201 9) |
*10.38 |  | Form of Severance Protection Agreement |
*31.1 |  | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
*31.2 |  | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
*32.1 |  | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
101. INS |  | Inline XBRL Instance Document |
101. SCH |  | Inline XBRL Taxonomy Extension Schema Document |
101. CAL |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
101. DEF |  | Inline XBRL Taxonomy Extension Definition Linkbase Document |
101. LAB |  | Inline XBRL Taxonomy Extension Labels Linkbase Document |
101. PRE |  | Inline XBRL Taxonomy Extension Presentation Linkbase |
104 |  | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |

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