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Item 7. Management’s Discussion and Analysis

2025-02-27 compared with 2024-02-23 · 53 added, 39 removed, 134 unchanged (41% of the section changed)

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

and other industry services which could expose Murphy to the impact of higher costs.

Murphy continues to strive toward safely executing our work in an ever-increasing efficient manner to mitigate possible inflationary pressures in our business.

Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher costs.

Murphy continues to strive toward safely executing our work in an ever-increasingly efficient manner to mitigate possible inflationary pressures in our business.

Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas.

Natural gas demand is also impacted by demand driven by lower carbon emissions and a view that natural gas is one option to transition from higher carbon emitting fuels.

Natural gas is also impacted by demand for lower carbon emissions.

As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

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Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations.

Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of ARO liabilities.

Downward reserves revisions can also lead to significant impairment expense.

The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods.

The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented on pages 103 to 112 of this Form 10-K report.

The Company’s proved reserves of crude oil, natural gas and NGLs are presented on pages 106 to 115 of this Form 10-K report.

Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), and commercially available technologies, to establish “reasonable certainty” of economic producibility.

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Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves.

Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates.

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Property, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheet to ensure that they are fairly presented.

The Company must evaluate its property, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows.

The Company must evaluate its property, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from undiscounted future net cash flows.

A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.

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Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated.

There were no impairments recognized in 2023 or 2022.

In 2024, the Company recognized pretax non-cash impairment charges of $62.9 million to reduce the carrying values at select properties.

In the first quarter of 2024, the Company recognized $34.5 million related to the Calliope field, in the Gulf of America, and in the fourth quarter of 2024, the Company recognized $28.4 million related to the Nearly Headless Nick field, in the Gulf of America.

Both of the impairment charges were due to subsurface issues that led to reserve reductions.

There were no impairments recognized in 2023.

See also Note D for further discussion of impairment charges.

Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates.

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and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.

The Company has deferred tax assets mostly relating to U.S net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant and equipment.

The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduce such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

In assessing the need for valuation allowances, we consider all available positive and negative evidence.

The Company has deferred tax assets mostly relating to U.S.

net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant and equipment.

The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduces such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

In assessing the need for valuation allowances,

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

we consider all available positive and negative evidence.

Positive evidence includes projected future taxable income and assessment of future business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences.

Negative evidence includes losses in recent years.

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

As of December 31, 2024 the Company had a U.S.

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In reviewing the likelihood of realizing this asset, the Company considered the reversal of taxable temporary differences, carryforward periods and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur.

Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil and condensate, NGLs and natural gas, (b) estimated reserves for crude oil and condensate, NGLs and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements.

Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil, natural gas and NGLs, (b) estimated reserves for crude oil, natural gas and NGLs, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements.

In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.

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Based on bond yields as of December 31, 2024, the Company has used a weighted average discount rate of 5.63% at year-end 2024 for the primary U.S.

This weighted average discount rate is 0.3% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago.

This weighted average discount rate is 0.5% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago.

The Company assumed a return on plan assets of 7.60% for the primary U.S.

plan, it periodically reconsiders the appropriateness of this and other key assumptions.

The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2024 are expected to be $0.7 million higher than in 2023 primarily due to the increase in the benefit obligations at December 31, 2023 compared to the prior year, which increases the interest cost recognized in net periodic benefit costs.

Cash contributions to all plans are anticipated to be $2.9 million higher in 2024.

plan and periodically reconsiders the appropriateness of this and other key assumptions.

The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2025 are expected to be $5.3 million lower than in 2024 primarily due to the decrease in the benefit obligations at December 31, 2024 compared to the prior year, which decreases the interest cost recognized in net periodic benefit costs.

In 2024, the Company paid $35.5 million into various retirement plans and $13.0 million into postretirement plans.

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Debt, excluding interest $ 1,284.8 $ — $ 78.9 $ 266.2 $ 939.7

Operating leases and other leases ¹ 1,019.3 245.7 148.4 125.4 499.8

Operating and finance leases 1,009.6 291.7 192.5 118.0 407.4

Capital expenditures, drilling rigs and other ¹ 1,294.4 469.8 339.2 160.2 325.2

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Total $ 6,206.8 $ 958.7 $ 872.6 $ 739.3 $ 3,636.2

1 Other leases refers to a finance lease in Brunei (see Note T ).

2 Capital expenditures, drilling rigs and other includes $51.6 million, $11.8 million, $11.6 million and $4.0 million, in 2024 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico, U.S.

Onshore, Canada Offshore and Other Foreign Offshore, respectively.

Capital expenditures, drilling rigs and other includes $23.5 million in 2025 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico.

1 Capital expenditures, drilling rigs and other includes $25.3 million, $13.7 million, $7.3 million and $1.1 million, in 2025 for approved capital projects in non-operated interests in the Gulf of America, U.S.

Onshore, Canada Offshore and Other Offshore, respectively.

Capital expenditures, drilling rigs and other includes $4.7 million in 2026 for approved capital projects in non-operated interests in the Gulf of America.

Also includes $73.1 million (2025), $138.4 million (2026 - 2027), $114.0 million (2028 - 2029) and $256.5 million (After 2029) for pipeline transportation commitments in Canada.

Also includes $3.6 million (2025), $7.1 million (2026 - 2027), $7.1 million (2028 - 2029) and $17.2 million (After 2029) for long-term take or pay commitments relating to natural gas processing in Canada.

3 Other long-term liabilities, including debt interest, includes future cash outflows for asset retirement obligations.

Also includes approximately $7.2 million (2025), $25.5 million (2026 - 2027), $25.3 million (2028 - 2029) and $120.0 million (After 2029) for Other Offshore for the purpose of supporting future development activities in Vietnam.

2 Other long-term liabilities, including debt interest, includes future cash outflows for ARO liabilities.

The Company has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that require future payments as described in the following section.

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Material off-balance sheet arrangements – Certain U.S.

transportation contracts require minimum monthly payments through 2045, while Onshore Canada transportation and processing contracts call for minimum monthly payments through 2051.

transportation contracts require minimum monthly payments through 2045, while Canada Onshore transportation and processing contracts call for minimum monthly payments through 2051.

Future required minimum annual payments under these arrangements are included in the contractual obligation table above.

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

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 a nd are aff ected by the levels of supply and demand for energy.

As discussed in the Results of Operations section discussing revenues, on page 37 , lower average crude oil price during in 2023 directly impacted the Company’s product sales revenue.

The oil and natural gas industry is impacted by global commodity pricing.

As a result, the prices for the Company’s primary products are often volatile a nd are aff ected by the levels of supply and demand for energy.

As discussed in the “ Results of Operations ” section on revenues, on page 37 , lower average crude oil price during 2024 directly impacted the Company’s product sales revenue.

As of close on February 25, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the table below:

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AECO (US$ Equivalent/MCF)

In 2023, liquids from continuing operations represented approximately 60% of total hydrocarbons produced on an energy equivalent basis.

In 2024, liquids from continuing operations represented approximately 56% of total hydrocarbons produced on a barrels of oil equivalent basis.

In 2025, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 57%.

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The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.

The Company currently expects average daily production in 2024 to be between 187,100 and 195,100 barrels of oil equivalent per day (including noncontrolling interest of 7,100 BOEPD).

The Company currently expects average daily production in 2025 to be between 181,100 and 189,100 BOEPD (including a noncontrolling interest of 6,600 BOEPD).

If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.

Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations.

Similar to the overall inflation and higher interest rates in the wider economy, the oil and natural 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.

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The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction.

Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022.

During 2023, the Board authorized a $300 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $600 million.

As of December 31, 2023, the Company has $450 million remaining available to repurchase.

The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F ).

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 F orm 8-K filed on August 8, 2024.

The Board has authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock.

As of December 31, 2024, the Company had $650.1 million of its common stock remaining available to repurchase under the program.

Subsequent to year end, as of February 25, 2025, the Company repurchased 3.4 million shares of its common stock in open-market transactions for $95.1 million, excluding taxes and fees.

As of this date, the Company had $555.0 million of its common stock remaining available to repurchase under the program.

In addition, subsequent to the balance sheet date, on January 30, 2025, the Board of Directors declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $0.325 per share, or $1.30 per

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

share on an annualized basis.

The dividend is payable on March 3, 2025, to stockholders of record as of February 18, 2025.

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 F ).

As of February 25, 2025, 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:

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Canada Natural Gas Fixed price forward sales 40 C$2.75 1/1/2025 12/31/2025

Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2024 10/31/2024

Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024

Canada Natural Gas Fixed price forward sales 50 C$3.03 1/1/2026 12/31/2026

(MMCF/d) Price/MCF Remaining Period

Area Commodity Type Start Date End Date

United States Natural Gas Fixed price derivative swap 40 US$3.58 2/1/2025 6/30/2025

United States Natural Gas Fixed price derivative swap 60 US$3.65 7/1/2025 9/30/2025

United States Natural Gas Fixed price derivative swap 60 US$3.74 10/1/2025 12/31/2025

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

Forward-Looking Statements

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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;

macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices;

geopolitical concerns;

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or adverse developments in the U.S.

or global capital markets, credit markets, banking system or economies in general, including inflation.

or global capital markets, credit markets, banking system or economies in general, including inflation and trade policies.

For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “ Item 1A.

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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 7. Management’s Discussion and Analysis