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Item 5. Market for Registrant’s Common Equity

2025-02-27 compared with 2024-02-23 · 170 added, 187 removed, 405 unchanged (47% of the section changed)

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s common stock is traded on the New York Stock Exchange using “MUR” as the trading symbol.

There were 1,974 stockholders of record as of December 31, 2023.

Information on dividends per share by quarter for 2023 and 2022 are reported on page 119 of this Form 10-K report.

Issuer Purchase of Equity Securities:

The following table summarizes repurchases of our common stock occurring in the fourth quarter 2023.

Period Total Number of Shares Purchased Average Price Paid Per Share 1

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs 2,3

(in thousands)

October 1 through October 31, 2023 – $ – – $ 525,000

November 1 through November 30, 2023 1,154,348 $ 43.29 1,154,348 $ 475,000

December 1 through December 31, 2023 572,288 $ 43.66 572,288 $ 450,000

1 Amounts exclude 1% excise tax and fees on share repurchases.

2 In August 2022, the Board authorized an initial share repurchase program of up to $300 million of the Company’s common stock.

On October 30, 2023, the Company authorized an increase to the share repurchase program by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.

Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws.

This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion.

3 Maximum approximate dollar values reported represent amounts at end of the month.

During 2023, the Company repurchased 3,411,158 shares of its common stock under the share repurchase program in open-market transactions for $150.0 million, excluding taxes and fees.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued

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The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2019 in the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index), the S&P Oil & Gas Exploration & Production Select Industry Index (XOP Index) and the Company’s peer group.

XOP Index reports a comprehensive view of the oil and gas exploration and production segment of the S&P Total Market Index which is more comparable for the Company than the S&P 500 Index.

XOP Index reports a comprehensive view of the oil and natural gas exploration and production segment of the S&P Total Market Index, which is more comparable for the Company than the S&P 500 Index.

Our peer group for 2024 is presented in the table below.

Callon Petroleum Company, Matador Resources Company and SM Energy Company were added to Murphy’s peer group in 2023 and CNX Resources Corporation was removed.

Civitas Resources Inc., EOG Resources Inc.

and Magnolia Oil & Gas Corporation were added to Murphy’s peer group in 2024.

Callon Petroleum Company, Hess Corporation and PDC Energy Inc.

were removed from Murphy’s peer group in 2024.

This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K report and it is not incorporated into any document that incorporates this Form 10-K report by reference.

The companies in the peer group included:

The companies in the peer group include:

APA Corporation Kosmos Energy Ltd.

Range Resources Corporation

Callon Petroleum Company

Marathon Oil Corporation SM Energy Company

Civitas Resources Inc.

Magnolia Oil & Gas Corporation

SM Energy Company

Coterra Energy Inc.

Matador Resources Company

Marathon Oil Corporation 1

Southwestern Energy Company 1

Devon Energy Corporation Ovintiv Inc.

Devon Energy Corporation Matador Resources Company

Talos Energy Inc.

Hess Corporation PDC Energy Inc.

EOG Resources Inc.

2019 2020 2021 2022 2023 2024

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XOP Index 100 65 121 192 192 181

1 PDC Energy Inc.

was acquired in 2023 and therefore has been excluded from the above table and graph of cumulative total return.

1 Marathon Oil Corporation and Southwestern Energy Company were acquired in 2024 and therefore have been excluded from the above table and graph of cumulative total return.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Discussion and analysis of 2022 results and year-over-year comparisons between 2023 and 2022 are not included in this Form 10-K and can be found in “Item 7” of the 2023 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with both onshore and offshore operations and properties.

The Company produces crude oil, natural gas and natural gas liquids primarily in the U.S.

and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide.

Murphy Oil Corporation is a worldwide oil and natural gas exploration and production company with both onshore and offshore operations and properties.

The Company produces crude oil, natural gas and NGLs primarily in the U.S.

and Canada and explores for crude oil, natural gas and NGLs in targeted areas worldwide.

A more detailed description of the Company’s significant assets can be found in “ Item 1 ” of this Form 10-K report.

The analysis and discussion in this section includes amounts attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

The analysis and discussion in this section includes amounts attributable to a noncontrolling interest (NCI) in MP GOM, unless otherwise noted.

Significant Company financial and operational highlights during 2024 were as follows:

• Generated net income of $661.6 million and net cash provided by operating activities of $1,748.8 million;

• Produced 193 thousand barrels of oil equivalent (BOE) per day (186 thousand excluding noncontrolling interest, NCI);

• Sanctioned the Lac Da Vang field development project in Vietnam;

• Enhanced exploration portfolio with signing production sharing contracts for five blocks in Côte d’Ivoire;

• Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico;

• Acquired an 8% working interest in the non-operated Zephyrus discovery in the Gulf of Mexico for a purchase price of approximately $13 million, net of closing adjustments;

• Resumed operations at non-operated Terra Nova field in offshore Canada during the fourth quarter of 2023, with production ramping up through first quarter 2024;

• Generated net income of $486.5 million ($407.2 million excluding NCI and net cash provided by operating activities of $1,729.0 million;

• Produced 184 thousand BOEPD (177 thousand BOEPD excluding NCI);

• Issued $600.0 million of 6.000% senior notes due 2032, and used proceeds to redeem an aggregate $600.0 million of senior notes due 2027, 2028 and 2029;

• Entered into a new five-year, $1.35 billion senior unsecured credit facility, representing a 69% increase from previous facility size;

• Advances made under the capital allocation framework 1 :

◦ Early debt retirement of approximately $500 million, a 27% debt reduction in the year

◦ Repurchased shares of common stock under the share repurchase program for $150 million, excluding excise taxes, commissions and fees

◦ Increased cash dividends by 10% since the fourth quarter of 2022 to $0.275 per share, or $1.10 per share annualized

• Achieved 134% (139% excluding NCI) total proved reserve replacement with year-end proved reserves of 739.5 million barrels of oil equivalent (724.0 million excluding NCI).

1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022.

On October 30, 2023, the initial share repurchase program of $300 million of the Company’s common stock was increased by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.

◦ Repurchased $50.0 million of long-term debt;

◦ Repurchased 8.0 million shares of common stock under the share repurchase program for $300.0 million ($302.7 million including excise taxes and fees);

• Achieved 84% (83% excluding NCI) total proved reserve replacement with year-end proved reserves of 729.0 million MMBOE (713.1 MMBOE excluding NCI);

• Drilled an oil discovery at Hai Su Vang-1X (Golden Sea Lion) in offshore Vietnam and encountered approximately 370 feet of net oil pay from two reservoirs;

• Drilled a discovery at the non-operated Ocotillo #1 exploration well in Mississippi Canyon 40 in the Gulf of America and found 100 feet of net pay across two zones.

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 Form 8-K filed on August 8, 2024.

The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of the Company’s common stock.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids, and natural gas in the United States and Canada and then selling these products to customers.

The Company’s revenue is affected by the prices of crude oil, natural gas and natural gas liquids.

Murphy’s continuing operations generate revenue by producing crude oil, natural gas and NGLs in the U.S.

and Canada and then selling these products to customers.

The Company’s revenue is affected by the prices of crude oil, natural gas and NGLs.

In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

For the year ended December 31, 2024, the Company’s net income from continuing operations was $489.3 million, a decrease of $235.9 million compared to 2023.

Lower net income from continuing operations was largely driven by lower revenues and other income ($472.5 million), higher lease operating expenses ($105.1 million) and higher exploration expenses ($101.6 million), partially offset by lower other operating expense ($91.0 million) and lower income tax expense ($113.5 million).

Lower revenues and other income resulted from overall lower pricing partially offset by overall higher sales volumes and lower losses on derivative instruments.

Higher lease operating expenses were related to higher sales volumes as well as additional costs for workover and maintenance activities at Gulf of Mexico operations.

Higher exploration costs were the result of dry hole expense for the Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells, that did not find commercial hydrocarbons in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire, and the expensing of previously suspended exploration costs for the Cholula-1EXP well in Mexico.

No losses were recorded in 2023 on derivative instruments as no fixed price derivative swaps or collar contracts were in effect during the period.

Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico.

Lower income tax expense was the result of lower pre-tax income.

For the year ended December 31, 2023, total hydrocarbon production was 192,640 barrels of oil equivalent per day, an increase of 10% compared to 2022.

The increase was principally due to new well production volumes in the Gulf of Mexico from the Khaleesi, Mormont, Samurai field development project, new well production from Tupper Montney and lower royalty rates, partially offset by lower production volumes at other fields in the Gulf of Mexico due to additional downtime.

Lower net income from continuing operations was largely driven by lower revenues and other income ($431.7 million), higher lease operating expenses ($152.7 million), and higher impairment expense ($62.9 million), partially offset by lower income tax expense ($117.6 million), lower exploration expenses ($101.2 million), higher other income ($79.5 million), lower other operating expense ($35.5 million) and lower transportation, gathering and processing costs ($22.2 million).

Lower revenues from production were primarily driven by mechanical and weather downtime in the Gulf of America, timing and performance of new wells at Eagle Ford Shale and lower average oil and natural gas prices, partially offset by wells brought back online at the non-operated Terra Nova field in the fourth quarter of 2023.

Higher lease operating expenses were primarily due to workovers in the Gulf of America and higher production activity in Canada at the Terra Nova field, partially offset by lower production handling fees in the Gulf of America.

Higher impairment expense is due to impairment of the Calliope and Nearly Headless Nick fields in the Gulf of America.

The decrease in income tax expense is primarily driven by lower overall income, in addition to an income tax deduction for prior years’ Australia exploration spend.

Exploration expenses in the current period was primarily due to dry hole expense recorded for multiple wells in the Gulf of America, including Sebastian #1 (Mississippi Canyon 387), non-operated Orange #1 (Mississippi Canyon 216), and for previously suspended exploration costs related to an expired lease at Hoffe Park #1 (Mississippi Canyon 166).

Higher other income related to unrealized foreign exchange gains and interest income on several outstanding joint interest receivables.

Lower other operating expense in 2024 is primarily driven by lower non-operated Terra Nova field start-up costs, contingency adjustments and asset retirement obligations (ARO) revisions.

Lower interest expense was due to lower debt levels.

Lower transportation, gathering and processing expenses related to lower production in the U.S.

For the year ended December 31, 2024, total hydrocarbon production was 184,293 BOEPD, a decrease of 4% compared to 2023.

The decrease was principally due to lower production in the U.S., primarily in the Gulf of America due to downtime for wells awaiting workovers and in the Eagle Ford Shale due to timing and performance of new wells and partially offset by the restart of production at the non-operated Terra Nova field in Canada in the first quarter of 2024.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations

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$ 407.2 $ 661.6 $ 965.0

1 The Company has presented its former U.K.

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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Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following are summarized income statements for E&P continuing operations.

The following is a summarized statement of operations for E&P continuing operations:

(Millions of dollars) 2024 2023 2022

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3,024.6 3,456.8 4,246.9

Cost and Expenses

Costs and Expenses

Lease operating expenses 937.0 784.4 679.3

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Accretion of asset retirement obligations 52.4 46.0 46.2

Total exploration expenses 234.8 133.1 69.0

Total exploration expenses, including undeveloped lease amortization

133.5 234.8 133.1

Selling and general expenses 23.8 37.7 44.5

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Canada - Onshore

681 903 1,117

Total net natural gas liquids

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Canada - Onshore

681 903 1,117

Total net natural gas liquids

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Revenues from production in 2024 decreased by $361.7 million compared to 2023.

Lower revenues from U.S.

E&P was primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher overall sales volumes from the Gulf of Mexico.

Higher sales volumes were driven by new well performance from the Khaleesi, Mormont, Samurai field development project, and were partially offset by lower sales volumes at other fields.

Lower revenues from Canadian E&P was primarily attributable to lower realized prices and lower sales volumes at Kaybob Duvernay partially offset by higher sales volumes at Tupper Montney.

Lower sales volumes at Kaybob Duvernay were primarily due to the divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, as well as natural declines.

Higher sales volumes at Tupper Montney were the result of new wells coming online in 2023, improved well performance, and lower royalty rates.

Revenue was lower in the Gulf of America, mostly driven by downtime for workovers, hurricane-related downtime and timing of new wells.

Eagle Ford Shale revenues decreased due to timing and performance of wells brought online.

These decreases were partially offset by wells brought back online in the fourth quarter of 2023 at non-operated Terra Nova.

Lower pricing across all products also contributed to the decrease during the period.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments.

Sales of purchase natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 34.

Other income was $8.0 million in 2023, a decrease of $18.7 million compared to 2022.

Lower other income was primarily the result of a gain on sale of the Thunder Hawk field in the third quarter of 2022.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

“Sales of purchased natural gas” is included in “Total revenues and other income” and “Costs of purchased natural gas” is included in “Costs and Expenses” in the summarized statement of operations for E&P continuing operations on page 33 .

Sales of purchased natural gas during 2024 were $3.7 million.

Lease Operating and Transportation, Gathering and Processing Expenses

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Total transportation, gathering and processing $ 210.8 $ 233.0 $ 212.7 $ 3.13 $ 3.32 $ 3.34

Lease operating expenses and transportation, gathering and processing expenses in 2023 increased by $105.1 million and $20.3 million, respectively, compared to 2022.

Higher lease operating expenses and increased transportation, gathering and processing expenses from U.S.

E&P were primarily due to increased sales volumes and higher operating expenses for additional workover and maintenance activities from the Gulf of Mexico operations.

Lease operating expenses and transportation, gathering and processing expenses in 2024 increased by $152.6 million and decreased by $22.2 million, respectively, compared to 2023.

Higher lease operating expenses were primarily due to workover costs in the Gulf of America, particularly at the Samurai and Neidermeyer fields, and the restart of the non-operated Terra Nova field in Canada Offshore in the first quarter of 2024.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

partially offset by lower production handling fees and lower overall volumes.

Lower transportation, gathering and processing expenses were primarily due to lower volumes.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization expense by geographic area were as follows:

The Company’s depreciation, depletion and amortization expense by geographic area was as follows:

(Millions of dollars) (Dollars per equivalent barrel)

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Depreciation, depletion and amortization expense (DD&A) in 2024 increased by $6.4 million compared to 2023.

Higher DD&A was primarily the result of higher sales volumes and higher rates from the Gulf of Mexico.

DD&A from Canadian E&P increased at Tupper Montney due to higher sales volumes and higher rates, substantially offset by lower sales volumes and lower rates at Kaybob Duvernay.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Higher DD&A was primarily the result of higher volumes at the non-operated Terra Nova field in Canada Offshore and higher rates at Eagle Ford Shale and in the Gulf of America, and was partially offset by lower volumes in the Gulf of America and lower rates and volumes at Kaybob Duvernay.

Impairment of Assets

In 2024 the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million.

In the first quarter of 2024, the Company recognized an impairment expense of $34.5 million for the Calliope field.

In the fourth quarter of 2024, an impairment expense of $28.4 million was recorded for the Nearly Headless Nick field.

Both fields were impaired as a result of operational issues that led to reserve reductions.

There were no impairments recorded in 2023.

Exploration Expenses

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$ 133.5 $ 234.8 $ 133.1

Exploration expenses in 2023 increased by $101.7 million compared to 2022.

Higher dry holes and previously suspended exploration costs primarily relate to the dry hole expense of Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells in the Gulf of Mexico, which encountered non-commercial hydrocarbons, and the write-off of previously suspended exploration costs for the Cholula-1EXP well in Mexico.

Higher geological and geophysical expenses in 2023 relate to the purchased seismic data for Côte d’Ivoire.

In 2022, dry holes and previously suspended exploration costs primarily relate to expensed costs for the Cutthroat-1 exploration well in block SEAL-M-428 in offshore Brazil and the Tulum-1EXP exploration well in Block 5 in offshore Mexico that did not encounter commercial hydrocarbons.

Exploration expenses in 2024 decreased by $101.3 million compared to 2023.

In 2024, dry holes and previously suspended exploration costs primarily related to the Sebastian #1 (Mississippi Canyon 387) exploration well, the non-operated Orange #1 (Mississippi Canyon 216) exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America.

In 2023, dry holes and previously suspended exploration costs related to previously suspended exploration costs for the Cholula-1EXP well in offshore Mexico and dry hole costs for the Chinook #7 (Walker Ridge 425) exploration well and the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America, both of which encountered non-commercial hydrocarbons.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Other Expenses

Other expenses were $0.3 million in 2024, a decrease of $56.6 million compared to 2023.

Other expenses were lower primarily due to a lower unfavorable contingent consideration adjustment of $7.1 million in 2023 (2022:

$78.3 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note O ).

In addition, there were lower asset retirement adjustments related to non-producing fields of $18.2 million in 2023 (2022:

$35.0 million).

Other expenses were lower primarily due to the absence of other operating expenses in Canada related to the non-operated Terra Nova life extension project, lower asset retirement adjustments, no contingent consideration adjustments in the current period and higher interest income received in 2024.

Income taxes were $106.3 million in 2024, a decrease of $131.5 million compared to 2023.

Lower income taxes were primarily the result of lower pre-tax income (see N ote H ).

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to E&P.

Realized and unrealized losses on derivative instruments would result from increases in market oil prices relating to future periods whereby the swap contracts provided the Company with a fixed price, and the collar contracts provided for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling.

Lower income taxes were primarily the result of lower pretax income, and an income tax deduction for prior years’ Australia exploration spend (see Note H ).

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge the price of oil sold) and corporate overhead not allocated to E&P.

Realized and unrealized losses on derivative instruments result from increases in market oil and natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

Corporate activities reported a loss of $109.1 million in 2024, a favorable variance of $46.9 million compared to 2023.

The favorable variance was primarily due to no current period losses on derivative instruments in 2023, compared to a loss for the same period in 2022 ($320.4 million) and lower interest expense ($38.6 million), partially offset by lower income tax benefits ($66.0 million) and foreign exchange loss of $10.7 million in 2023 compared to foreign exchange gain of $23.0 million in 2022.

Interest charges are lower in 2023 primarily due to lower overall debt levels as the Company reduced debt by $498.2 million and $647.7 million during 2023 and 2022, respectively.

During 2023 and as of December 31, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding.

Lower income tax benefit was a result of lower pre-tax losses.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The favorable variance was primarily due to foreign exchange gain of $45.4 million in 2024 compared to foreign exchange loss of $10.7 million in 2023, primarily as a result of unrealized exchange rate changes relating to our Canadian subsidiary.

Interest charges are lower in 2024 primarily due to lower overall debt levels.

The lower income tax benefit was the result of a lower current period loss before income tax.

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.

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, as described below.

The Company’s liquidity requirements, both in the short-term (2025) and long-term (beyond 2025), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.

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

The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 months.

The following table presents the Company’s cash flows for the periods presented.

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Net cash provided by continuing operations activities in 2024 was $19.8 million lower compared to 2023.

The decrease was primarily attributable to lower revenue from production ($661.9 million), higher payments of contingent consideration related to prior Gulf of Mexico acquisitions ($139.6 million), higher lease operating expenses ($105.1 million) and timing of working capital settlements ($33.6 million), partially offset by lower realized losses on derivative instruments ($535.2 million).

Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows;

The decrease was primarily attributable to lower revenue from production ($361.7 million) and higher lease

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

operating expenses costs ($152.6 million), partially offset by a decrease due to timing of non-cash working capital ($174.2 million) settlements, no contingent consideration payments related to prior Gulf of America acquisitions in 2024 (2023:

$139.6 million), lower exploration expenses ($101.2 million), and changes in other operating activities, net ($56.4 million) primarily due to decreased expenditures for asset retirements.

Payments of contingent consideration in 2023 are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows;

amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition.

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During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows.

As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.

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 America acquisitions.

See Note O for further details.

The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in “Financing Activities”) during the two years ended December 31, 2023, and 2022 were $108.9 million and $150.0 million, respectively.

Lower cash interest paid in 2023 was primarily due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.050% senior notes due 2029 (2029 Notes) in the aggregate amount of $498.2 million.

The total reductions of operating cash flows for interest paid (which excludes “Early redemption of debt cost” reported in “Financing Activities”) during the two years ended December 31, 2024, and 2023 were $78.8 million and $108.9 million, respectively.

Cash interest paid in 2024 was primarily due to interest payments on outstanding debt.

Some of these payments related to accelerated interest payments due to the early redemption, in part, of the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.05% senior notes due 2029 (2029 Notes) in the aggregate redemption amount of $650.1 million.

In 2023, cash interest paid was higher than 2024, primarily due to higher debt levels in 2023 and accelerated interest payments due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 2027 Notes, the 2028 Notes, and the 2029 Notes for an aggregate redemption amount of $498.2 million.

Cash Required by Investing Activities

Net cash required by investing activities in 2024 was $90.5 million lower compared to 2023.

The decrease was primarily due to the proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million) and lower acquisition capital ($93.0 million), partially offset by higher property additions and dry hole costs ($80.6 million).

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The decrease was primarily due to lower property additions and dry hole costs ($157.9 million) and lower acquisition capital ($35.6 million), partially offset by the absence of proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million).

A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

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Geophysical and other exploration expenses 44.8 46.0 30.6

Acquisition of oil properties per the cash flow statements 1

35.6 128.5 20.3

Acquisition of oil and natural gas properties per the cash flow statements

Capital expenditure accrual changes and other 11.8 (9.5) 38.6

Property additions King's Quay Floating Production System (FPS) per cash flow statements

Total capital expenditures $ 964.8 $ 1,138.1 $ 1,183.2

1 Certain prior-period amounts have been reclassified to conform to the current period presentation.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Total accrual basis capital expenditures are shown below.

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Total capital expenditures excluding proved property acquisitions and NCI $ 952.8 $ 1,040.8 $ 1,028.8

Lower capital expenditures in 2023 compared to 2022 were primarily attributable to lower development expenditures at the Khaleesi, Mormont, Samurai field development project, lower spend at the Kodiak and Lucius fields and lower acquisition capital, partially offset by higher exploratory drilling and higher development expenditures at the Dalmatian and St.

Capital expenditures in 2023 primarily relate to development drilling and field development activities in the Eagle Ford Shale ($361.5 million);

development activities in the Gulf of Mexico, primarily related to St.

Malo, Dalmatian, Samurai and Marmalard fields ($310.1 million);

development drilling and field development activities at the Tupper Montney field ($142.0 million);

field development at Terra Nova for the asset life extension project ($44.7 million);

and total exploration costs of $214.3 million.

Exploration costs were primarily for activities at Chinook #7 (Walker Ridge 425), Oso #1 (Atwater Valley 138) and Longclaw #1 (Green Canyon 433) within the Gulf of Mexico and activities at Côte d’Ivoire.

Costs of $169.8 million primarily associated with Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) were expensed to dry hole costs in 2023 as the Company determined there were non-commercial hydrocarbons present.

Lower capital expenditures in 2024 compared to 2023 were primarily attributable to lower development expenditures at Eagle Ford Shale, Tupper Montney, and non-operated Terra Nova and lower exploration expenses in the Gulf of America, partially offset by higher exploration and development costs in offshore Vietnam.

Capital expenditures in 2024 primarily relate to development drilling and field development activities in the Gulf of America, primarily related to the Mormont, Khaleesi, Lucius, St.

Malo and Samurai fields ($306.9 million), at Eagle Ford Shale ($291.8 million), at Tupper Montney and Kaybob Duvernay ($116.3 million), at other international locations ($45.1 million), and at non-operated Hibernia ($18.2 million).

In addition, total exploration costs were $153.9 million.

Exploration costs in 2024 were primarily comprised of activities in the Gulf of America related to the Sebastian #1 (Mississippi Canyon 387), Orange #1 (Mississippi Canyon 216), and non-operated Oso #1 (Atwater Valley 138) exploration wells.

Sebastian #1 and Orange #1 encountered non-commercial hydrocarbons during 2024.

Non-operated Oso #1 encountered non-commercial hydrocarbons in 2023, and operations completed in 2024.

Additional exploratory costs relate to oil discoveries, including the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well in Vietnam, as well as other ongoing projects.

Cash Required by Financing Activities

Net cash required by financing activities in 2024 decreased by $207.2 million compared to 2023.

In 2023, cash used in financing activities was principally for the redemption of the remaining $248.7 million principal outstanding on its 2025 Notes and the tendering of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes.

In addition, the Company repurchased common shares ($150.0 million, excluding accrued excise tax), paid contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the ‘Cash Provided by Continuing Operating Activities’ section, paid cash dividends to shareholders of $1.10 per share ($171.0 million), and distributed funds to the noncontrolling interest in the Gulf of Mexico ($29.4 million).

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

In 2024, cash used in financing activities was principally for the repurchase of common shares ($301.4 million, excluding excise tax).

In addition, the Company completed a refinancing transaction whereby new senior notes due 2032 were issued in the aggregate amount of $600.0 million and the proceeds were used for the aggregate repayment and repurchase of $600.0 million of its 2027 Notes, 2028 Notes and 2029 Notes.

The Company also repurchased $50.0 million of its 2027 Notes, paid cash dividends to shareholders of $1.20 per share ($180.0 million), and distributed funds to the noncontrolling interest in MP GOM ($118.6 million).

At December 31, 2024, the Company had approximately $1.8 billion of liquidity consisting of $423.6 million in cash and cash equivalents and $1,349.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $800 million senior unsecured RCF expires in November 2027 and as of December 31, 2023, the Company had no outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF.

Borrowings under the RCF are subject to certain interest rates, please refer to Note F for further details.

The Company’s $1.35 billion senior unsecured RCF expires in October 2029.

As of December 31, 2024, the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF.

Borrowings under the RCF are subject to certain interest rates.

Please refer to Note F for further details.

At December 31, 2024, the interest rate in effect on borrowings under the facility would have been 6.68%.

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As of December 31, 2024, cash and cash equivalents held outside the U.S.

included U.S dollar equivalents of approximately $148.9 million (2022:

$147.7 million), the majority of which was held in Canada ($105.2 million) and Mexico ($18.1 million).

included U.S.

dollar equivalents of approximately $95.2 million (2023:

$149 million), the majority of which was held in Canada ($58.5 million), Vietnam ($8.7 million) and Brunei ($8.5 million).

In addition, approximately $7.8 million and $6.4 million of cash was held in the U.K.

and Spain, respectively.

In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S.

and Mexico, respectively.

In certain cases, the Company could incur cash taxes or other costs should these cash balances be

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

repatriated to the U.S.

in future periods.

Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

See Note H for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

See Note H for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the U.S.

Working Capital

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$ (157.5) $ (94.3)

As of December 31, 2023, net working capital had a favorable increase of $191.2 million compared to December 31, 2022.

The favorable increase was primarily attributable to lower other accrued liabilities ($302.8 million) and lower accounts payable ($96.9 million), partially offset by lower accounts receivable ($47.2 million) and a lower cash balance ($174.9 million).

Lower accrued liabilities were primarily due to payments made for contingent consideration obligations from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made in 2023.

Lower accounts payable were primarily due to decreases in unrealized losses on derivative instruments (commodity price swaps and collars), decreases in royalties payable due to lower revenues, payments made for abandonment activities and drilling and completions activities.

Lower unrealized losses on derivative instruments were as a result of no commodity derivative instrument contracts entered into or outstanding during 2023.

Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas liquids and lower pricing received for all crude oil, natural gas liquids and natural gas.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

As of December 31, 2024, net working capital had an unfavorable decrease of $63.2 million compared to December 31, 2023.

The decrease was primarily attributable to lower accounts receivable ($71.5 million), higher operating lease liabilities ($45.4 million), higher current ARO liabilities ($37.4 million), and higher accounts payable ($25.3 million), partially offset by a higher cash balance ($106.5 million).

Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas, and lower pricing received for all crude oil, natural gas and NGLs.

Higher operating lease liabilities are primarily due to an extension of an existing drilling ship lease in the Gulf of America.

Higher current ARO liabilities are primarily due to certain Gulf of America obligations to be completed in 2025.

Higher accounts payable are due to the timing of payments for certain drilling activities and ongoing workover projects.

Capital Employed

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Total capital employed $ 6,468.8 100.0 % $ 6,691.2 100.0 %

As of December 31, 2023, long-term debt decreased by $494.0 million compared to December 31, 2022, as a result of the redemption and early redemption of, in whole or in part, the 2025 Notes, 2027 Notes, 2028 Notes, and 2029 Notes.

The fixed-rate notes had a weighted average maturity of 8.1 years and a weighted average coupon of 6.2%.

Murphy’s shareholders’ equity increased by $368.0 million in 2023 primarily due to net income earned ($661.6 million), partially offset by cash dividends paid ($171.0 million) and shares repurchased ($150.0 million, including excise tax).

As of December 31, 2024, long-term debt decreased by $53.9 million compared to December 31, 2023, as a result of the repurchase of the 2027 Notes and 2028 Notes.

The Company also completed a refinancing transaction whereby it issued $600.0 million of 2032 Notes, and used all of the proceeds to complete the repurchase and redemption, in whole or in part, of the 2027 Notes, 2028 Notes, and 2029 Notes.

As of December 31, 2024, the fixed-rate notes had a weighted average maturity of 9.3 years and a weighted average coupon of 6.1%.

Refer to Note F for additional details.

Murphy’s shareholders’ equity decreased by $168.5 million in 2024 primarily due to cash dividends paid ($180.0 million), shares repurchased ($302.7 million, including excise tax), and foreign currency translation losses ($134.7 million), partially offset by net income earned ($407.2 million).

A summary of transactions in stockholders’ equity accounts is presented in the “ Consolidated Statements of Stockholders’ Equity " on page 70 of this Form 10-K report.

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Other significant changes in Murphy’s balance sheet at the end of 2024, compared to 2023 are discussed below.

Property, plant and equipment, net of depreciation, decreased $2.8 million principally due to DD&A expense ($861.6 million) and divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, substantially offset by capital expenditures in the year and foreign exchange rates applicable for the Canadian assets.

Capital expenditures are discussed above in the ‘Cash Required for Investing Activities’ section.

Property, plant and equipment, net of depreciation decreased $170.5 million principally due to DD&A expense and foreign exchange rates applicable for the Canadian assets, substantially offset by capital expenditures in the year.

Capital expenditures are discussed above in the “Cash Required by Investing Activities” section.

Murphy had commitments for capital expenditures of approximately $417.0 million at December 31, 2024 (2023:

$209.8 million).

This amount includes $75.1 million for approved expenditures for capital projects relating to non-operated interests in deepwater U.S.

Gulf of Mexico, principally at St.

Malo ($61.7 million), non-operated Canada interests, mainly offshore ($11.6 million), non-operated Lucius ($13.3 million) and non-operated Eagle Ford Shale ($11.8 million).

Operating lease assets decreased $201.2 million principally due to depreciation on these assets.

Deferred Income tax assets decreased by $117.5 million as a result of the decrease in the U.S.

net operating loss carryforward from $2.1 billion at year-end 2022 to $1.7 billion at year-end 2023.

Long term asset retirement obligations increased $86.8 million primarily due to accretion and additions and revisions related to Gulf of Mexico and Eagle Ford Shale operations.

This amount includes $220.0 million for Other Offshore, primarily related to approved expenditures for capital projects relating to interests in Vietnam for the Lac Da Vang (Golden Camel) field development project, $112.2 million at Eagle Ford Shale, primarily at the Karnes field, $53.6 million relating to

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Gulf of America interests, primarily at the Mormont and non-operated St.

Malo fields, and $31.2 million relating to interests in Canada Onshore, primarily at Kaybob Duvernay.

Operating lease assets increased $32.4 million principally due to lease extensions in the Gulf of America, partially offset by the depreciation of these assets.

Long-term ARO liabilities increased $56.8 million primarily due to accretion, additions and revisions related to Gulf of America and Eagle Ford Shale operations.

Non-current operating lease liabilities decreased $14.5 million primarily due to 2024 annual payments reducing operating lease liabilities for drilling rig and vessel commitments.

Deferred income tax liabilities increased $61.7 million due to capital related tax deductions.

Deferred income tax liabilities increased $59.1 million due to utilization of the net operating loss, partially offset by other capital-related tax effect s.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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The Company uses other operational performance and income metrics to review operational performance.

Management uses adjusted net income, EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

Adjusted net income also excludes certain items that management believes affect the comparability of results between periods.

Management 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 affects the comparability of results between periods.

Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

Adjusted net income, EBITDA, adjusted EBITDA and are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

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.

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410.0 663.1 967.1

Adjustments 2 :

Write-off of previously suspended exploration wells 17.1 22.7 –

Asset retirement obligation losses (gains) 16.9 30.8 (71.8)

Foreign exchange loss (gain)

Impairment of assets 62.9 — —

Write-off of previously suspended exploration well

26.1 17.1 22.7

Mark-to-market loss on contingent consideration

Foreign exchange (gain) loss

(45.4) 10.9 (23.0)

Mark-to-market (gain) loss on derivative instruments

Refinancing and early redemption of debt costs (non-cash)

Mark-to-market loss (gain) on derivative instruments

1.7 — (214.7)

Asset retirement obligation losses

Mark-to-market loss on contingent consideration

(Gain) on sale of assets — — (14.5)

Early redemption of debt cost – 10.3 43.9

Impairment of assets – – 196.3

Tax benefits on investments in foreign areas – – (8.9)

Charges related to Kings Quay transaction – – 4.9

Unutilized rig charges – – 8.7

Total adjustments, before taxes

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Income tax (benefit) expense related to adjustments (8.3) (6.4) 23.8

Tax (benefit) on investments in foreign areas

Total adjustments after taxes 6.7 45.6 (86.3)

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$ 2.72 $ 4.23 $ 6.14

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 4.52 $ 5.59 $ 1.29

Adjusted net income from continuing operations attributable to Murphy per average diluted share (Non-GAAP)

$ 2.76 $ 4.52 $ 5.59

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

2 Certain prior-period amounts have been reclassified to conform to the current period presentation.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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EBITDA attributable to Murphy (Non-GAAP) 1,424.5 1,806.6 2,173.5

Impairment of assets 1

Accretion of asset retirement obligations 1

46.9 41.0 40.9

Write-off of previously suspended exploration well 17.1 22.7 –

Asset retirement obligation loss (gain)

16.9 30.8 (71.8)

Foreign exchange loss (gain)

10.8 (23.0) (1.0)

Mark-to-market loss gain on contingent consideration

7.1 78.3 63.2

Mark-to-market (gain) loss on derivative instruments

Foreign exchange (gain) loss

(45.4) 10.8 (23.0)

Write-off of previously suspended exploration well 26.1 17.1 22.7

Discontinued operations loss

Mark-to-market loss (gain) on derivative instruments

1.7 — (214.7)

Mark-to-market loss on contingent consideration

Asset retirement obligation losses

Gain on sale of assets 1

Impairment of assets 2

Unutilized rig charges – – 8.7

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 1,519.5 $ 1,901.0 $ 2,096.1

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

2 Depreciation, depletion and amortization expense, impairment of assets, loss (gain) on sale of sale of assets and accretion of asset retirement obligations used in the computation of adjusted EBITDA exclude the portion attributable to the noncontrolling interest.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels.

The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, and through emergency and oil spill response planning to address any credible risks.

The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, auditing and assessments, and through emergency and oil spill response planning to address any credible risks.

These plans are presented to, reviewed and approved by a Health, Safety, Environment and Corporate Responsibility Committee consisting of certain members of the Board.

The oil and gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations.

The oil and natural gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations.

Murphy allocates a portion of both its capital expenditures and its general and administrative budget toward compliance with existing and anticipated environmental, health and safety laws and regulations.

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The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials;

the emission and discharge of such materials to the environment, including GHG emissions;

the emission and discharge of such materials to the environment, including methane and other GHG emissions;

wildlife, habitat and water protection;

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Climate Change and Emissions

The world’s population and standard of living is growing steadily along with the demand for energy.

The world’s population and standard of living are growing steadily along with the demand for energy.

Murphy recognizes that this may generate increasing amounts of GHG, which could raise important climate change concerns.

Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the TCFD core elements.

The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of climate-related financial information.

Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2023 Sustainability Report issued on August 2, 2023, which is not incorporated by reference hereto.

While oversight of the TCFD framework has undergone changes, including relating to the role of the International Financial Reporting Standards Foundation in overseeing the framework, the TCFD framework continues to inform climate-related reporting practices.

Murphy’s disclosures related to its alignment with the TCFD framework are included in the Company’s 2024 Sustainability Report issued on August 7, 2024, which is not incorporated by reference hereto.

Other Matters

Impact of inflation – In 2023, many countries worldwide continued to experience a rise in inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021).

In the U.S., inflation continued as a result of ongoing supply constraints and increasing demand for goods and services as countries continue their recovery from the COVID-19 pandemic.

The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas industry and allied industries rather than by changes in general inflation.

Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ production levels and/or attitudes of traders concerning supply and demand in the future.

Impact of inflation – In 2024, many countries worldwide continued to experience moderate inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021).

The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry and allied industries rather than by changes in general inflation.

Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC and certain non-OPEC members’ production levels and/or attitudes of traders concerning supply and demand in the future.

Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.

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Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services.

However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs

However, from time to time,

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity