MURPHY OIL CORP
For the period ended Dec 31, 2025. Filed Feb 25, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 25, 2026
MUR$35.96-1.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-27.
0000717423-25-000006
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsRevenues from ProductionOutlookForward-Looking StatementsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-25.
0001628280-26-011709
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsRevenues from ProductionOutlookForward-Looking StatementsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 168 previous paragraphs and 172 current paragraphs.
74 unchanged; 65 reworded; 33 added; 27 removed; 2 previous and 0 current paragraphs rearranged.
Tables are not compared: 21 previous and 21 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (33)
Current report
•Closed the strategic acquisition of the Pioneer floating production, storage and offloading vessel (FPSO) in the Gulf of America for a gross purchase price of $125.0 million; and
Current report
•Drilled oil discoveries at the Lac Da Hong-1X (Pink Camel), Block 15-1/05 and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells in Vietnam.
Current report
Subsequent to year end:
Current report
•Upsized senior unsecured revolving credit facility from$1.35 billion to$2.00 billionand extended maturity from 2029 to 2031;
Current report
•Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced a dry hole at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire; and
Current report
•Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share.
Current report
For the year ended December 31, 2025, the Company’s net income from continuing operations was $138.3 million, a decrease of $351.0 million compared to 2024. Lower net income from continuing operations was largely driven by lower revenues and other income ($309.7 million), higher depreciation, depletion and amortization expense (DD&A) ($112.0 million), higher other losses ($93.2 million), higher impairment expense ($52.1 million) and higher selling and general expenses ($27.2 million). These items were partially offset by lower lease operating expenses ($171.7 million), lower income tax expense ($33.7 million), and lower exploration expenses ($21.9 million).
Current report
Lower revenues from production were primarily driven by lower average oil prices and lower volumes in the Gulf of America due to downtime and the natural decline of new wells, and was partially offset by increased production in the Eagle Ford Shale due to new wells and improved performance, as well as higher realized natural gas prices in Canada, at the Tupper Montney. Higher DD&A was primarily due to increased production and higher rates in the Eagle Ford Shale, and higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America. Higher other losses were mainly due to unrealized losses on foreign exchange related to our Canada business and were partially offset by lower interest expenses due to no debt repayment fees in the current year. Impairment expense of $115.0 million in 2025 was related to the impairment of the Dalmatian property due to reserve reductions, as certain projects in the field were less competitive for capital allocation. Higher selling and general expenses were due to higher salary and compensation costs in 2025. Lower lease operating expenses were due to lower workovers in the current year, combined with lower operating costs related to the purchase of the Pioneer FPSO. Lower income tax expense was primarily attributable to lower taxable income and was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend. Lower exploration expenses were due to lower dry hole costs in the current period, which related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, and was partially offset by higher exploration, geological, geophysical and other costs related to the Company’s U.S. Offshore and Côte d’Ivoire exploration programs.
Current report
For the year ended December 31, 2025, total hydrocarbon production was 188,682 BOEPD, an increase of 2% compared to 2024. The increase was principally due to higher production in the Eagle Ford Shale and Canada Onshore and was partially offset by lower production in the Gulf of America. Increased production in the Eagle Ford Shale was driven primarily by the performance of new wells online in the current year at Karnes and Catarina. Higher production in Canada Onshore related to better well performance at the Tupper Montney. Lower production in the Gulf of America related to planned and unplanned downtime and was partially offset by new wells online.
Current report
3 Proved reserves at December 31, 2025, 2024 and 2023, include 15.0 MMBOE, 15.9 MMBOE and 15.5 MMBOE, respectively, attributable to NCI.
Current report
Revenues from production in 2025 decreased by $325.1 million compared to 2024. Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline, and downtime for maintenance at Khaleesi. These decreases were partially offset by wells online at Mormont and Neidermeyer in the Gulf of America, improved performance, new wells, and the acquisition of additional working interests in the Eagle Ford Shale, and new wells and improved performance in the Tupper Montney. Higher realized gas pricing in the period was also an offset to the decrease in revenue.
Current report
Gain on Sale of Assets and Other Operating Income
Current report
Other income was $17.6 million in 2025, an increase of $11.6 million compared to 2024. Higher other income was primarily the result of a gain recognized on contingent consideration related to the 2022 sale of working interests in Block CA-2 in Brunei.
Current report
Lease operating expenses and transportation, gathering and processing expenses in 2025 decreased by $171.8 million and $11.1 million, respectively, compared to 2024. Lower lease operating expenses were primarily due to lower workover costs in the Gulf of America, lower operating costs as a result of the acquisition of the Pioneer
Current report
FPSO and lower production handling fees. In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, and were partially offset by higher volume related costs.
Current report
In the third quarter of 2025, the Company recorded impairment costs in the Gulf of America totaling $115.0 million ($92.0 million excluding NCI), related to the partial write-down of the Dalmatian field due to reserve reductions, as certain projects in the field were less competitive for capital allocation.
Current report
Selling and general expenses were $46.2 million in 2025, an increase of $22.4 million compared to 2024. Selling and general expenses were higher due to higher salary and long-term incentive compensation costs primarily related to a higher average share price throughout 2025.
Current report
Total other losses were $16.5 million in 2025, an increase of $16.2 million compared to 2024. The increase was primarily due to no repeat of interest income on outstanding joint interest receivables that was received in 2024.
Current report
Net cash required by investing activities in 2025 was $120.8 million higher compared to 2024. The increase was primarily due to higher property additions ($120.5 million) and higher acquisition capital ($21.0 million), partially offset by proceeds from realization of contingent consideration receivable from the 2022 sale of Brunei assets.
Current report
Total capital expenditures categorized by E&P and corporate activities are presented below.
Current report
Higher capital expenditures in 2025 compared to 2024 were primarily attributable to the Pioneer FPSO purchase in the Gulf of America, exploratory and development drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign, and exploratory drilling in Côte d’Ivoire.
Current report
Capital expenditures of $1,218.0 million in 2025 were primarily related to development drilling ($551.4 million), field development ($400.2 million) and exploration ($221.7 million) activities. Development activities were mainly in the Gulf of America ($330.8 million), primarily related to the Cascade and Chinook, Mormont,
Current report
Zephyrus, and Other Offshore fields, the Eagle Ford Shale ($365.4 million), the Tupper Montney and the Kaybob Duvernay ($133.9 million), and Vietnam ($98.5 million).
Current report
Exploration costs in 2025 were $221.7 million, primarily attributable to activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05, and Hai Su Vang-1X and Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17 exploration wells, activities in the Gulf of America related to the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d’Ivoire related to the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells.
Current report
Net cash required by financing activities in 2025 decreased by $452.4 million compared to 2024. In 2025, cash used in financing activities was principally for year-to-date cash dividends to shareholders of $1.30 per share ($186.2 million), the repurchase of common shares ($102.6 million), excluding excise tax, distributions to the noncontrolling interest in MP GOM ($63.8 million), and partially offset by net borrowings on the RCF ($100.0 million).
Current report
2 Other exploration expenses consist of exploration expenses as reported in the Consolidated Statements of Operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.
Current report
Management uses FCF and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.
Current report
The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.
Current report
1 Property additions for the year ended December 31, 2025 include a payment of $125.0 million for the Pioneer FPSO in the U.S. Offshore, including amounts attributable to the noncontrolling interest in MP GOM.
Current report
In 2025, the Company recognized a pretax non-cash impairment charge of $115.0 million ($92.0 million excluding NCI) to reduce the carrying value at the Dalmatian field, in the Gulf of America, as certain projects in the field were less competitive for capital allocation.
Current report
Subsequent to the balance sheet date, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In January 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its 6.500% senior notes due 2034 (2034 Notes), used the proceeds to redeem an aggregate $227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. See Note F for additional information.
Current report
Subsequent to the balance sheet date, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In January 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its 2034 Notes, used the proceeds to redeem an aggregate $227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. In addition, the Company entered into an amendment to its credit agreement which increased its RCF capacity from $1.35 billion to $2.0 billion and extended the term of the agreement to 2031. See Note F for additional information on these transactions.
Removed paragraphs (27)
Previous report
•Entered into a new five-year, $1.35 billion senior unsecured credit facility, representing a 69% increase from previous facility size;
Previous report
•Advances made under the capital allocation framework 1:
Previous report
◦Repurchased $50.0 million of long-term debt;
Previous report
•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
Previous report
•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.
Previous report
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.
Previous report
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.
Previous report
3 NCI – noncontrolling interest in MP GOM.
Previous report
4 December 31, 2024, 2023 and 2022, include 15.9 MMBOE, 15.5 MMBOE and 18.2 MMBOE, respectively, relating to
Previous report
noncontrolling interest.
Previous report
3 NCI – noncontrolling interest in MP GOM.
Previous report
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.
Previous report
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.
Previous report
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 partially offset by lower production handling fees and lower overall volumes. Lower transportation, gathering and processing expenses were primarily due to lower volumes.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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).
Previous report
Total accrual basis capital expenditures are shown below.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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).
Previous report
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.
Previous report
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.
Previous report
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.
Reworded paragraphs (65)
Previous wording
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.
Current wording
Murphy Oil Corporation is a worldwide oil and natural gas E&P company with both onshore and offshore operations and properties. The Company produces oil and natural gas 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.
Previous wording
•Generated net income of $486.5 million ($407.2 million excluding NCI and net cash provided by operating activities of $1,729.0 million;
Current wording
•Generated net income of $138.8 million ($104.2 million excluding NCI) and net cash provided by operating activities of $1,247.8 million;
Previous wording
•Produced 184 thousand BOEPD (177 thousand BOEPD excluding NCI);
Current wording
•Produced 189 thousand BOEPD (182 thousand BOEPD excluding NCI);
Previous wording
◦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);
Current wording
•Repurchased 3.6 million shares of common stock under the share repurchase program for $100.0 million ($100.8 million including excise taxes and fees) under the capital allocation plan 1;
Previous wording
•Achieved 84% (83% excluding NCI) total proved reserve replacement with year-end proved reserves of 729.0 million MMBOE (713.1 MMBOE excluding NCI);
Current wording
•Achieved 101% (103% excluding NCI) total proved reserve replacement with year-end proved reserves of 730.0 million MMBOE (715.0 MMBOE excluding NCI);
Previous wording
•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;
Current wording
•Issued $500.0 million of 6.50% senior notes due in 2034 and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028;
Previous wording
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.
Current wording
1 Details of the capital allocation plan 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.
Previous wording
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.
Current wording
Murphy’s continuing operations generate revenue by producing oil and natural gas in the U.S. and Canada and then selling these products to customers. The Company’s revenue is affected by the prices of oil and natural gas. In order to make a profit and generate cash in its E&P 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.
Previous wording
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.
Current wording
1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
Previous wording
The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.
Current wording
The following section of E&P continuing operations excludes the Corporate segment, unless otherwise noted.
Previous wording
1 Prices include the effect of noncontrolling interest in MP GOM.
Current wording
1 Prices include the effect of the noncontrolling interest in MP GOM.
Previous wording
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
Current wording
1 Includes net volumes attributable to the noncontrolling interest in MP GOM.
Previous wording
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
Current wording
1 Includes net volumes attributable to the noncontrolling interest in MP GOM.
Previous wording
The Company’s depreciation, depletion and amortization expense by geographic area was as follows:
Current wording
The Company’s DD&A expense by geographic area was as follows.
Previous wording
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.
Current wording
DD&A in 2025 increased by $112.5 million compared to 2024. The increase was primarily due to higher sales volumes and higher rates in the Eagle Ford Shale, higher rates in the Gulf of America, and was partially offset by lower production in the Gulf of America.
Previous wording
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.
Current wording
In 2024, the Company recorded impairment costs for two assets in the Gulf of America, totaling $62.9 million. In the first quarter, the Company recognized an impairment expense of $34.5 million for the Calliope field. In the fourth quarter, 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.
Previous wording
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.
Current wording
Exploration expenses in 2025 decreased by $21.8 million compared to 2024. In 2025, dry holes were related to the operated Civette-1X (Block CI-502) exploration well in Côte d’Ivoire. 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. The decrease due to lower dry hole costs was partially offset by increases to geological, geophysical and other exploration costs, related to the Company’s Gulf of America and Côte d'Ivoire exploration programs.
Previous wording
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).
Current wording
Income taxes were $90.2 million in 2025, a decrease of $16.1 million compared to 2024. Lower income taxes were primarily the result of lower pretax income. This was partially offset by the non-recurrence of an income tax deduction that occurred in 2024 relating to prior years’ Australian exploration spend.
Previous wording
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.
Current wording
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 natural gas sold) and corporate overhead not allocated to E&P. Realized and unrealized losses on derivative instruments result from increases in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.
Previous wording
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.
Current wording
Corporate activities reported a loss of $158.4 million in 2025, an unfavorable variance of $49.3 million compared to 2024. The unfavorable variance was primarily due to a foreign exchange loss of $29.4 million in 2025 compared to a foreign exchange gain of $45.4 million in 2024, as a result of unrealized exchange rate changes relating to our Canadian subsidiary. This increase was partially offset by lower interest charges in 2025 due to no debt repayment fees in the current year, and a higher income tax benefit attributable to our Canadian segment as a result of larger current-period losses before income taxes, primarily as a result of foreign exchange.
Previous wording
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.
Current wording
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF, as described below. The Company’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), 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.
Previous wording
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 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.
Current wording
Net cash provided by continuing operations activities in 2025 was $481.2 million lower compared to 2024. The decrease was primarily attributable to lower revenue from production ($325.1 million), timing of non-cash working capital ($148.9 million) settlements, changes in other operating activities, net ($68.4 million), primarily due to decreased expenditures for asset retirements, and higher other expenses ($93.2 million), primarily due to Canadian foreign exchange losses, partially offset by lower lease operating expenses ($171.7 million) and lower exploration expenses $21.9 million.
Previous wording
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.
Current wording
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, 2025, and 2024 were $88.1 million and $78.8 million, respectively. Cash interest paid in 2025 was primarily due to interest payments on outstanding debt. In 2025, cash interest paid was higher than 2024, primarily due to amounts drawn on the RCF. In 2024, cash interest paid was primarily due to interest payments on outstanding debt and 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) for an aggregate redemption amount of $650.1 million.
Previous wording
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.
Current wording
At December 31, 2025, the Company had approximately $1.6 billion of liquidity consisting of $377.2 million in cash and cash equivalents and $1,249.6 million available on its previous RCF with a major banking consortium.
Previous wording
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.
Current wording
The Company’s previous $1.35 billion RCF was set to expire in October 2029, and as of December 31, 2025, the Company had $100.0 million outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. Borrowings under the RCF were subject to certain interest rates. Please refer to Note F for further details. At December 31, 2025, the interest rate in effect on borrowings under the facility was 6.04%. At December 31, 2025, the Company was in compliance with all covenants related to the RCF. Subsequent to year end, in January, 2026, the Company entered into an Amended RCF, a credit agreement governing a $2.0 billion senior unsecured guaranteed revolving credit facility, with a maturity date in January 2031, which increased and extended the previous RCF.
Previous wording
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 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 Hfor further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the U.S.
Current wording
Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $152.5 million (2024: $95.2 million), the majority of which was held in Canada ($76.5 million), Brunei ($23.7 million), Côte d’Ivoire ($21.6 million), and Vietnam ($8.5 million). In addition, approximately $7.8 million and $7.0 million of cash was held in Mexico and the U.K., respectively. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S. See Note Hfor further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the U.S.
Previous wording
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.
Current wording
As of December 31, 2025, net working capital had an unfavorable decrease of $88.5 million compared to December 31, 2024. The decrease was primarily attributable to higher accounts payable ($100.0 million), higher operating lease liabilities ($25.6 million), and a lower cash balance ($46.4 million), partially offset by higher accounts receivable ($74.2 million). Higher accounts payable were primarily due to the timing of payments for certain drilling activities and ongoing workover projects. Higher operating lease liabilities were primarily due to the addition of a new drilling rig and support vessels in Vietnam, partially offset by the purchase of the Pioneer FPSO and normal amortization of leases. Higher accounts receivable were due primarily to timing of partner billing and related cash calls, partially offset by lower pricing.
Previous wording
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.
Current wording
As of December 31, 2025, long-term debt increased by $108.1 million compared to December 31, 2024, primarily as a result of amounts drawn on the RCF. As of December 31, 2025, the fixed-rate notes had a weighted average maturity of 8.3 years and a weighted average coupon of 6.1%. Refer to Note F for additional details.
Previous wording
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.
Current wording
Murphy’s shareholders’ equity decreased by $75.9 million in 2025 primarily due to dividends ($186.2 million) and shares repurchased ($100.8 million), including excise tax, partially offset by foreign currency translation ($74.0 million), net income ($104.2 million), and awarded restricted stock ($22.4 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity" on page 72 of this Form 10-K report.
Previous wording
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.
Current wording
Property, plant and equipment, net of depreciation, increased $81.7 million principally due to capital expenditures in the year, partially offset by DD&A expense ($977.8 million) and foreign exchange rates applicable for the Canadian assets. Capital expenditures are discussed above in the “Cash Required by Investing Activities” section.
Previous wording
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
Current wording
Murphy had commitments for capital expenditures of approximately $551.2 million at December 31, 2025 (2024: $417.0 million). This amount primarily related to approved expenditures of $127.5 million in Vietnam for the Lac Da Vang (Golden Camel) field development project, $45.0 million for exploration activities in Côte d’Ivoire, $82.6 million in the Eagle Ford Shale, $245.3 million relating to Gulf of America interests, primarily related to Cascade and Chinook operated field and exploration activities, as well as $49.8 million relating to interests in Canada Onshore, primarily at the Kaybob Duvernay.
Previous wording
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.
Current wording
Operating lease assets increased $27.9 million principally due to lease additions in Vietnam, partially offset by the depreciation of these assets.
Previous wording
Deferred income tax liabilities increased $59.1 million due to utilization of the net operating loss, partially offset by other capital-related tax effects.
Current wording
Deferred income tax liabilities increased $42.5 million due to utilization of our net operating loss, partially offset by other capital-related tax effects.
Previous wording
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.
Current wording
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), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for net income or cash provided by operating activities as determined in accordance with GAAP.
Previous wording
The following table reconciles reported net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
Current wording
The following table reconciles net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
Previous wording
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
Current wording
1 Excludes amounts attributable to the noncontrolling interest in MP GOM.
Previous wording
The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.
Current wording
The following table reconciles net income attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.
Previous wording
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
Current wording
1 Excludes amounts attributable to the noncontrolling interest in MP GOM.
Previous wording
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.
Current wording
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 of facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.
Previous wording
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.
Current wording
Impact of inflation – In 2025, inflation in the U.S. and in other countries where the Company operates began to moderate relative to the sustained higher inflation seen since 2021. However, U.S. and global trade policy is continually developing, and it is unclear whether this trend will continue or reverse as we enter 2026 and beyond. 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+ 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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Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
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.