Item 5. Market for Registrant’s Common Equity
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued
SHAREHOLDER RETURN PERFORMANCE PRESENTATION
The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 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 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. 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 include:
APA Corporation Kosmos Energy Ltd. Range Resources Corporation
Civitas Resources Inc.
Magnolia Oil & Gas Corporation
SM Energy Company
Coterra Energy Inc. Marathon Oil Corporation 1
Southwestern Energy Company 1
Devon Energy Corporation Matador Resources Company
Talos Energy Inc.
EOG Resources Inc.
Ovintiv Inc.
2019 2020 2021 2022 2023 2024
Murphy Oil Corporation 100 47 104 176 179 131
Peer Group 100 64 132 201 191 180
S&P 500 Index 100 118 152 125 158 197
XOP Index 100 65 121 192 192 181
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.
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Item 6. RESERVED
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the consolidated financial statements and accompanying notes to consolidated financial statements, which are included in Item 8 of this Annual Report on Form 10-K. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “ Forward-Looking Statements ” at the end of this section and “ Risk Factors ” under Item 1A. Discussion and analysis of 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 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 (NCI) in MP GOM, unless otherwise noted.
Significant Company financial and operational highlights during 2024 were as follows:
• 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 :
◦ 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; and
• 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.
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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 ($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.
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Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below:
( Millions of dollars )
2024 2023 2022
Exploration and production
United States $ 561.9 $ 905.1 $ 1,521.9
Canada 49.0 41.6 134.2
Other International (12.5) (65.5) (77.0)
Total exploration and production
598.4 881.2 1,579.1
Corporate and other (109.1) (156.0) (438.3)
Income from continuing operations
489.3 725.2 1,140.8
Loss from discontinued operations 1
(2.8) (1.5) (2.1)
Net income including noncontrolling interest
486.5 723.7 1,138.7
Net income attributable to noncontrolling interest
79.3 62.1 173.7
Net income attributable to Murphy
$ 407.2 $ 661.6 $ 965.0
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.
E&P Continuing Operations: 2024 vs 2023
The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.
Please also refer to “ Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities ” in the Supplemental Oil and Natural Gas Information section for additional supporting tables.
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The following is a summarized statement of operations for E&P continuing operations:
(Millions of dollars) 2024 2023 2022
Revenues and other income
Revenue from production
$ 3,014.9 $ 3,376.6 $ 4,038.5
Sales of purchased natural gas
3.7 72.2 181.7
Other income
6.0 8.0 26.7
Total revenues and other income
3,024.6 3,456.8 4,246.9
Costs and Expenses
Lease operating expenses 937.0 784.4 679.3
Severance and ad valorem taxes 39.2 42.8 57.0
Transportation, gathering and processing 210.8 233.0 212.7
Costs of purchased natural gas 3.1 51.7 172.0
Depreciation, depletion and amortization 856.9 850.5 763.9
Impairments of assets 62.9 — —
Accretion of asset retirement obligations 52.4 46.0 46.2
Total exploration expenses, including undeveloped lease amortization
133.5 234.8 133.1
Selling and general expenses 23.8 37.7 44.5
Other 0.3 56.9 141.8
Results of operations before taxes 704.7 1,119.0 1,996.4
Income tax provisions
106.3 237.8 417.3
Results of operations (excluding Corporate segment) 1
$ 598.4 $ 881.2 $ 1,579.1
1 Includes results attributable to a noncontrolling interest in MP GOM.
Pricing
The following table contains the weighted average sales prices for the three years ended December 31, 2024:
(Weighted average sales prices)
2024 2023 2022
Crude oil and condensate – dollars per barrel
United States - Onshore $ 75.77 $ 76.96 $ 96.00
United States - Offshore 1
76.36 77.38 94.21
Canada - Onshore 2
67.49 72.84 89.88
Canada - Offshore 2
82.22 84.20 107.47
Other 2
77.59 86.60 94.37
Natural gas liquids – dollars per barrel
United States - Onshore 20.20 19.69 33.85
United States - Offshore 1
23.37 21.94 36.01
Canada - Onshore 2
34.14 35.87 55.65
Natural gas – dollars per thousand cubic feet
United States - Onshore 1.90 2.26 6.04
United States - Offshore 1
2.40 2.78 6.97
Canada - Onshore 2
1.59 2.06 2.76
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
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The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2024:
(Average price for the period) 2024 2023 2022
Oil and NGLs
WTI ($/BBL) $ 75.72 $ 77.62 $ 94.23
Natural gas
NYMEX ($/MMBTU) 2.24 2.53 6.38
AECO (C$/MCF) 1.46 2.64 5.31
Production Volumes
The following table contains hydrocarbons produced during the three years ended December 31, 2024. For further discussion on volumes, please see “ Revenues from Production ” section on page 37 .
(Barrels per day unless otherwise noted) 2024 2023 2022
Net crude oil and condensate
United States - Onshore
21,151 24,070 24,437
United States - Offshore 1
63,047 73,473 65,411
Canada - Onshore
2,868 2,937 4,005
Canada - Offshore
7,251 3,020 2,812
Other 219 250 700
Total net crude oil and condensate
94,536 103,750 97,365
Net natural gas liquids
United States - Onshore
4,442 4,617 5,181
United States - Offshore 1
4,544 5,924 4,597
Canada - Onshore
597 681 903
Total net natural gas liquids
9,583 11,222 10,681
Net natural gas – thousands of cubic feet per day
United States - Onshore
25,028 25,863 29,050
United States - Offshore 1
57,228 70,239 63,380
Canada - Onshore
398,786 369,906 310,230
Total net natural gas
481,042 466,008 402,660
Total net hydrocarbons - including NCI 2,3
184,293 192,640 175,156
Noncontrolling interest
Net crude oil and condensate – barrels per day (6,358) (6,210) (7,452)
Net natural gas liquids – barrels per day (199) (220) (280)
Net natural gas – thousands of cubic feet per day (1,942) (2,089) (2,468)
Total noncontrolling interest 2,3
(6,881) (6,778) (8,143)
Total net hydrocarbons - excluding NCI 2,3
177,412 185,862 167,013
Estimated total proved net hydrocarbon reserves
- million equivalent barrels 3,4
729.0 739.5 715.4
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
4 December 31, 2024, 2023 and 2022, include 15.9 MMBOE, 15.5 MMBOE and 18.2 MMBOE, respectively, relating to
noncontrolling interest.
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Sales Volumes
The following table contains hydrocarbons sold during the three years ended December 31, 2024. For further discussion on volumes, please see “ Revenues from Production ” section on page 37 .
(Barrels per day unless otherwise noted) 2024 2023 2022
Net crude oil and condensate
United States - Onshore
21,151 24,070 24,437
United States - Offshore 1
63,612 73,373 64,840
Canada - Onshore
2,868 2,937 4,005
Canada - Offshore
6,445 2,559 3,002
Other 230 349 663
Total net crude oil and condensate
94,306 103,288 96,947
Net natural gas liquids
United States - Onshore
4,443 4,617 5,181
United States - Offshore 1
4,543 5,924 4,597
Canada - Onshore
597 681 903
Total net natural gas liquids
9,583 11,222 10,681
Net natural gas – thousands of cubic feet per day
United States - Onshore
25,028 25,863 29,050
United States - Offshore 1
57,228 70,239 63,380
Canada - Onshore
398,786 369,906 310,230
Total net natural gas
481,042 466,008 402,660
Total net hydrocarbons - including NCI 2,3
184,063 192,178 174,738
Noncontrolling interest
Net crude oil and condensate – barrels per day (6,438) (6,200) (7,369)
Net natural gas liquids – barrels per day (198) (220) (280)
Net natural gas – thousands of cubic feet per day (1,942) (2,089) (2,468)
Total noncontrolling interest 2,3
(6,960) (6,768) (8,060)
Total net hydrocarbons - excluding NCI 2,3
177,103 185,410 166,678
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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Revenues from Production
The Company’s production revenues by country and product were as follows:
(Millions of dollars) 2024 2023 2022
Revenues from production
United States - Oil $ 2,364.3 $ 2,748.5 $ 3,085.9
United States - Natural gas liquids 71.7 80.6 124.4
United States - Natural gas
67.8 92.7 225.3
Canada - Oil 264.8 156.7 249.2
Canada - Natural gas liquids 7.4 8.9 18.3
Canada - Natural Gas
232.3 278.2 312.6
Other - Oil
6.6 11.0 22.8
Total revenues from production
$ 3,014.9 $ 3,376.6 $ 4,038.5
Revenues from production in 2024 decreased by $361.7 million compared to 2023. 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 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
The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:
(Millions of dollars) (Dollars per equivalent barrel)
2024 2023 2022 2024 2023 2022
Lease operating expenses
United States – Onshore
$ 141.9 $ 150.3 $ 137.6 $ 13.02 $ 12.48 $ 10.94
United States – Offshore
608.0 480.4 385.1 21.38 14.46 13.19
Canada – Onshore 132.6 140.3 139.5 5.18 5.89 6.75
Canada – Offshore 52.9 11.5 15.6 22.43 12.30 14.20
Other 1.6 1.9 1.5 18.52 14.94 6.25
Total lease operating expenses $ 937.0 $ 784.4 $ 679.3 $ 13.91 $ 11.18 $ 10.65
Transportation, gathering and processing
United States – Onshore
$ 9.6 $ 12.7 $ 18.4 $ 0.88 $ 1.05 $ 1.47
United States – Offshore
121.3 144.3 123.8 4.27 4.34 4.24
Canada – Onshore 75.5 72.2 65.3 2.95 3.03 3.16
Canada – Offshore 4.4 3.8 5.2 1.85 4.12 4.76
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 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. These were
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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 was as follows:
(Millions of dollars) (Dollars per equivalent barrel)
2024 2023 2022 2024 2023 2022
Depreciation, depletion and amortization expense
United States – Onshore
$ 319.9 $ 316.7 $ 321.4 $ 29.36 $ 26.29 $ 25.55
United States – Offshore
389.3 389.3 295.6 13.69 11.72 10.12
Canada – Onshore 123.5 133.4 128.1 4.82 5.60 6.20
Canada – Offshore 22.5 8.8 13.4 9.55 9.47 12.25
Other 1.7 2.3 5.4 20.13 18.05 22.19
Total depreciation, depletion and amortization expense
$ 856.9 $ 850.5 $ 763.9 $ 12.72 $ 12.12 $ 11.98
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 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
The Company’s exploration expenses were as follows:
(Millions of dollars) 2024 2023 2022
Exploration expenses
Dry holes and previously suspended exploration costs $ 73.2 $ 169.8 $ 82.1
Geological and geophysical 27.2 26.1 10.4
Other exploration 23.5 28.0 27.3
Undeveloped lease amortization 9.6 10.9 13.3
Total exploration expenses
$ 133.5 $ 234.8 $ 133.1
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.
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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 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
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 pretax income, and an income tax deduction for prior years’ Australia exploration spend (see Note H ).
Corporate: 2024 vs 2023
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 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, 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.
Cash Flows
The following table presents the Company’s cash flows for the periods presented.
(Millions of dollars) 2024 2023 2022
Net cash provided by (required by):
Net cash provided by continuing operations activities $ 1,729.0 $ 1,748.8 $ 2,180.2
Net cash required by investing activities
(908.2) (998.7) (1,109.4)
Net cash required by financing activities
(716.5) (923.7) (1,081.6)
Net cash required by discontinued operations
— — (14.5)
Effect of exchange rate changes on cash and cash equivalents 2.2 (1.2) (3.9)
Net (decrease) increase in cash and cash equivalents
$ 106.5 $ (174.8) $ (29.2)
Cash Provided by Continuing Operations Activities
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 ($361.7 million) and higher lease
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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. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities.
During 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of America acquisitions. See Note O for further details.
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 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.
Year Ended December 31,
(Millions of dollars) 2024 2023 2022
Property additions and dry hole costs per cash flow statements
$ 908.2 $ 1,066.0 $ 985.5
Geophysical and other exploration expenses 44.8 46.0 30.6
Acquisition of oil and natural gas properties per the cash flow statements
— 35.6 128.5
Capital expenditure accrual changes and other 11.8 (9.5) 38.6
Total capital expenditures $ 964.8 $ 1,138.1 $ 1,183.2
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Total accrual basis capital expenditures are shown below.
Year Ended December 31,
(Millions of dollars) 2024 2023 2022
Capital Expenditures
Exploration and production $ 935.7 $ 1,114.0 $ 1,161.5
Corporate 29.1 24.1 21.7
Total capital expenditures 964.8 1,138.1 1,183.2
Total capital expenditures excluding proved property acquisitions 964.8 1,111.0 1,054.7
Total capital expenditures excluding proved property acquisitions and NCI $ 952.8 $ 1,040.8 $ 1,028.8
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 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).
Liquidity
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 $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%. At December 31, 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 December 31, 2024, cash and cash equivalents held outside the U.S. 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 Mexico, respectively. In certain cases, the Company could incur cash taxes or other costs should these cash balances be
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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 U.S.
Working Capital
(Millions of dollars) December 31, 2024 December 31, 2023
Working capital
Total current assets $ 785.3 $ 752.2
Total current liabilities 942.8 846.5
Net working capital liability
$ (157.5) $ (94.3)
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
A summary of capital employed as of December 31, 2024 and 2023 follows.
December 31, 2024 December 31, 2023
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 1,274.5 19.7 % $ 1,328.4 19.9 %
Murphy shareholders' equity 5,194.3 80.3 % 5,362.8 80.1 %
Total capital employed $ 6,468.8 100.0 % $ 6,691.2 100.0 %
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.
Other Balance Sheet Activity - Long-Term Assets and Liabilities
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 $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 $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
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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 $59.1 million due to utilization of the net operating loss, partially offset by other capital-related tax effect s.
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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 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, 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.
Year Ended December 31,
(Millions of dollars)
2024 2023 2022
Net income attributable to Murphy (GAAP) 1
$ 407.2 $ 661.6 $ 965.0
Discontinued operations loss 2.8 1.5 2.1
Net income from continuing operations attributable to Murphy
410.0 663.1 967.1
Adjustments:
Impairment of assets 62.9 — —
Write-off of previously suspended exploration well
26.1 17.1 22.7
Foreign exchange (gain) loss
(45.4) 10.9 (23.0)
Refinancing and early redemption of debt costs (non-cash)
3.7 — 10.3
Mark-to-market loss (gain) on derivative instruments
1.7 — (214.7)
Asset retirement obligation losses
— 16.9 30.8
Mark-to-market loss on contingent consideration
— 7.1 78.3
(Gain) on sale of assets — — (14.5)
Total adjustments, before taxes
49.0 52.0 (110.1)
Income tax (benefit) expense related to adjustments (8.3) (6.4) 23.8
Tax (benefit) on investments in foreign areas
(34.0) — —
Total adjustments after taxes 6.7 45.6 (86.3)
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 416.7 $ 708.7 $ 880.8
Net income from continuing operations per average diluted share (GAAP)
$ 2.72 $ 4.23 $ 6.14
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.
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The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.
Year Ended December 31,
(Millions of dollars)
2024 2023 2022
Net (loss) income attributable to Murphy (GAAP) 1
$ 407.2 $ 661.6 $ 965.0
Income tax expense 78.3 195.9 309.5
Interest expense, net 105.9 112.4 150.8
Depreciation, depletion and amortization expense 1
833.1 836.7 748.2
EBITDA attributable to Murphy (Non-GAAP) 1,424.5 1,806.6 2,173.5
Impairment of assets 1
62.9 — —
Accretion of asset retirement obligations 1
46.9 41.0 40.9
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
2.8 1.5 2.1
Mark-to-market loss (gain) on derivative instruments
1.7 — (214.7)
Mark-to-market loss on contingent consideration
— 7.1 78.3
Asset retirement obligation losses
— 16.9 30.8
Gain on sale of assets 1
— — (14.5)
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.
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Environmental, Health and Safety Matters
Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, 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 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. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities as well as operating costs for ongoing compliance.
The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other GHG emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.
Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the “ Business ” section beginning page 9 .
Climate Change and Emissions
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 framework. 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 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.
To combat impacts of inflation and/or supply and demand factors, Murphy has dedicated personnel in marketing and procurement departments, focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services. However, from time to time,
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