MURPHY OIL CORP
For the period ended Jun 30, 2024. Filed Aug 8, 2024.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2024 · Filed Aug 8, 2024
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-Q
Period ended 2024-03-31; filed 2024-05-02.
0000717423-24-000013
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2024-06-30; filed 2024-08-08.
0000717423-24-000026
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe 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 98 previous paragraphs and 115 current paragraphs.
57 unchanged; 31 reworded; 24 added; 9 removed; 1 previous and 3 current paragraphs rearranged.
Tables are not compared: 18 previous and 18 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 (24)
Current report
•Drilled a discovery at the non-operated Ocotillo #1 exploration well in Mississippi Canyon 40 in the Gulf of Mexico
Current report
•Maintained quarterly dividend of $0.30 per share or $1.20 per share annualized
Current report
•Advanced the capital allocation framework 1:
Current report
◦Repurchased $55.9 million ($56.4 million including excise taxes and fees) of common stock, or 1,361,350 shares, at an average price of $41.03 per share
Current report
◦Completed the open market repurchase of approximately $50.0 million of long-term debt notes
Current report
Subsequent to the second quarter of 2024:
Current report
•As of August 7, 2024 the Company repurchased $44.1 million ($44.6 million including excise taxes and fees) of common stock, or 1,142,867 shares, and had $800 million of its common stock available to repurchase under the program
Current report
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2024, was $156.9 million, an increase of $64.4 million compared to the same period in 2023. Higher net income from continuing operations was largely driven by lower exploration costs ($73.1 million), higher other income ($33.9 million) and lower interest expense on long-term debt ($8.9 million), partially offset by higher lease operating costs ($65.3 million). The decrease in exploration costs were driven primarily by lower dry hole costs related to the Orange #1 (Mississippi Canyon 216) exploration well that encountered non-commercial hydrocarbons in the second quarter of 2024. In the second quarter of 2023, exploration costs included dry hole costs relating to the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico, and previously suspended exploration costs for the Cholula-1EXP well in Mexico. Higher other income related to foreign exchange gains and interest income on several outstanding joint interest receivables and lower interest expense on long-term debt related to debt repayments since the prior period. These were partially offset by increased workover costs in the Gulf of Mexico.
Current report
Overview (Continued)
Current report
For the three months ended June 30, 2024 total hydrocarbon production was 187,847 barrels of oil equivalent per day, a decrease of 1% compared to the second quarter of 2023. The decrease was principally due to lower production in the U.S., primarily at the Eagle Ford Shale due to a lower number of new wells on production, and in the Gulf of Mexico due to downtime and timing of new wells . Decreases in the U.S. were offset by increases in Canada at both Tupper Montney, due to new wells online, and Terra Nova, which restarted production in late 2023.
Current report
Revenues from production for the three months ended June 30, 2024 decreased $2.3 million compared to the same period in 2023. Lower revenue was driven by increased workovers, downtime and timing of wells in the Gulf of Mexico, fewer wells brought online in the Eagle Ford Shale and lower realized natural gas prices in Tupper Montney. These effects were partially offset by increased production due to prior period downtime and improved well performance in the Gulf of Mexico, the Terra Nova field restarting production in the fourth quarter of 2023, new wells online at Tupper Montney, and higher oil prices.
Current report
Revenues from production for the six months ended June 30, 2024 decreased $4.0 million compared to the same period in 2023. Lower revenues were primarily related to workovers and downtime in the Gulf of Mexico, fewer new wells brought online in the Eagle Ford Shale, and lower realized natural gas prices in Tupper Montney. These effects were partially offset by new wells online at Tupper Montney, restarting production at Terra Nova in late 2023, and higher oil prices.
Current report
For the three months ended June 30, 2024 lease operating expenses increased by $65.3 million and TGP expenses decreased by $6.5 million, compared to the same period in 2023. Higher lease operating expenses were due to workover activity at the Neidermeyer field in the Gulf of Mexico, higher production at Terra nova, and were partially offset by lower production handling fees in the Gulf of Mexico. Lower TGP expenses during the quarter were a result of lower production volumes in the Gulf of Mexico.
Current report
For the six months ended June 30, 2024, lease operating expenses increased by $99.7 million and TGP expenses decreased by $3.8 million, compared to the same period in 2023. Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico and higher production at Terra Nova. Lower TGP expenses resulted primarily from lower production volumes in the Gulf of Mexico.
Current report
DD&A expense for the three months ended June 30, 2024 decreased by $0.1 million, compared to the same period in 2023. The decrease is primarily due to lower production volumes in U.S. Offshore and Onshore, offset by increased rates in the Gulf of Mexico, and higher production volumes in Canada Offshore and Onshore.
Current report
Exploration expenses for the three months ended June 30, 2024 decreased by $73.0 million compared to the prior year, primarily the result of lower dry hole costs in the current period. Dry hole costs in the current period represented costs associated with the Orange #1 (Mississippi Canyon 216) non-operated exploration well in the U.S. Gulf of Mexico, that encountered non-commercial hydrocarbons in the second quarter of 2024. In the second quarter of 2023, we recorded expenses related to previously suspended exploration costs at the Cholula-1EXP well in Mexico, as well as dry hole costs related to Chinook #7 (Walker Ridge 425) exploration well in U.S. Gulf of Mexico.
Current report
Exploration expenses for the six months ended June 30, 2024 decreased by $38.8 million compared to the same period in 2023. In the current period, dry hole costs were recorded for the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and for the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the U.S. Gulf of Mexico. In 2023, we recorded previously suspended exploration costs for the Cholula-1EXP well in Mexico and dry hole costs for the Chinook #7 (Walker Ridge 425) exploration well in the U.S. Gulf of Mexico.
Current report
Other
Current report
Other expenses for the three and six months ended June 30, 2024 decreased by $27.5 million and $32.4 million, respectively, compared to the same periods in 2023. This decrease was due to a combination of interest income received, and a favorable tax settlement related to U.S. Onshore activities.
Current report
Net cash provided by continuing operations activities for the six months ended June 30, 2024 was $116.7 million higher compared to the same period in 2023. The increase was primarily attributable to no contingent consideration payments related to prior Gulf of Mexico acquisitions in 2024 (2023: $139.6 million), lower spend on abandonments in 2024 ($62.0 million), and higher other income ($19.3 million).These increases were partially offset by increased lease operating expenses ($99.6 million).
Current report
Capital expenditures in 2024 primarily relate to development drilling and field development activities at Eagle Ford Shale ($164.7 million), at Tupper Montney ($71.2 million) and Kaybob Duvernay ($24.1 million) in Canada, and at the Khaleesi, Mormont, Samurai, Lucius and St. Malo fields in the Gulf of Mexico ($182.9 million). Other international field development activities were ($15.5 million), and total exploration costs were $84.1 million.
Current report
As of June 30, 2024 net working capital decreased by $75.9 million compared to December 31, 2023. The decrease was primarily attributable to higher accounts payable ($60.9 million) and higher operating lease liabilities ($46.9 million). The decrease was partially offset by lower other accrued liabilities ($26.1 million) and a higher cash balance ($16.5 million).
Current report
Higher operating lease liabilities are primarily attributable to the current portion of lease extensions recorded during the period related to a drill ship in the U.S. Gulf of Mexico (See Note Q for additional detail). Higher accounts payable were primarily due to workover activity in the U.S. Gulf of Mexico, and other timing of cash payments.
Current report
Subsequent to the second quarter of 2024, the Company repurchased 1,142,867 shares of its common stock in open-market transactions for $44.1 million, excluding taxes and fees. As of August 7, 2024, the Company had $800 million of its common stock remaining available to repurchase under the program.
Removed paragraphs (9)
Previous report
•Exploration areas expanded with the award of six deepwater blocks from Gulf of Mexico Federal Lease Sale 261
Previous report
•Repurchased shares of our common stock under the share repurchase program for $50.0 million, including excise taxes, commissions and fees.
Previous report
Revenue from production for the three months ended March 31, 2024 decreased by $1.6 million compared to the same period in 2023. Lower revenue from U.S. E&P was primarily attributable to lower sales volumes from the Gulf of Mexico due to increased downtime for workovers, partially offset by higher sales volumes at Eagle Ford Shale assets from new well production and higher realized prices at both Eagle Ford Shale assets and the Gulf of Mexico. Higher revenue from Canadian E&P was primarily attributable to higher sales volumes from Terra Nova and Tupper Montney fields, partially offset by lower pricing at Tupper Montney and lower sales volumes from Kaybob Duvernay fields. Tupper Montney had an increase in volumes as a result of new well production and lower royalty rates, while lower volumes at Kaybob Duvernay resulted from the divestiture of certain non-core operated assets and all of our non-operated Placid Montney assets during the second half of 2023. The Terra Nova field in Canada Offshore restarted production during the fourth quarter of 2023 after completion of the asset life extension project.
Previous report
Lease operating expenses and TGP expenses for the three months ended March 31, 2024 increased by $34.3 million and $2.6 million, respectively, compared to the same period in 2023. Higher lease operating expenses from US E&P was due to workovers in the Gulf of Mexico. Higher lease operating expenses and TGP from Canada E&P resulted from ramp up of production at the Terra Nova field since the completion of the asset life extension project in the fourth quarter of 2023.
Previous report
Other Expenses
Previous report
Other expenses for the three months ended March 31, 2024 decreased by $4.8 million compared to the same period in 2023. Other expenses were lower primarily due to an unfavorable contingent consideration adjustment of $3.9 million recorded in 2023 related to prior Gulf of Mexico acquisitions (see Note L).
Previous report
Financial Condition (Continued)
Previous report
Financial Condition (Continued)
Previous report
As of March 31, 2024, net working capital had a favorable increase of $37.0 million compared to December 31, 2023. The favorable increase was primarily attributable to lower other accrued liabilities ($39.5 million), lower operating lease liabilities ($28.4 million), higher accounts receivable ($12.9 million), and a higher cash balance ($6.4 million), partially offset by higher accounts payable ($39.0 million). Lower accrued liabilities were primarily due to incentive payments and lower operating lease liabilities were primarily due to 2024 payments reducing drilling rig and vessel lease liabilities. Higher accounts receivable and higher accounts payable were primarily due to the timing of cash receipts and cash payments, respectively.
Reworded paragraphs (31)
Previous wording
Murphy Oil Corporation is a global oil and gas exploration and production company, with both onshore and offshore operations and properties. The Company produces crude oil, natural gas and natural gas liquids primarily in the U.S. and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide. Our production in the U.S. is primarily from fields in the Gulf of Mexico and in the Eagle Ford Shale area of South Texas. In Canada, we produce from the Tupper Montney and Kaybob Duvernay fields in British Columbia and Alberta, and we produce from the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin.
Current wording
Murphy Oil Corporation is a global oil and gas exploration and production company, with both onshore and offshore operations and properties. The Company produces crude oil, natural gas and natural gas liquids primarily in the U.S. and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide. Our production in the U.S. is primarily from offshore fields in the Gulf of Mexico and onshore in the Eagle Ford Shale area of South Texas. In Canada, we produce from the onshore fields Tupper Montney and Kaybob Duvernay, in British Columbia and Alberta, and we produce from the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin.
Previous wording
Significant Company financial and operational highlights during the first quarter of 2024 were as follows:
Current wording
Significant Company financial and operational highlights during the second quarter of 2024 were as follows:
Previous wording
•Production during the quarter was 176,671 barrels of oil equivalent per day (including NCI).
Current wording
•Produced 187,847 barrels of oil equivalent per day (including NCI) during the quarter
Previous wording
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended March 31, 2024 was $115.6 million, a decrease of $98.5 million compared to the same period of 2023. Lower net income from continuing operations was largely driven by higher lease operating expenses ($34.3 million), higher exploration expenses ($34.2 million), and higher impairment of assets ($34.5 million), partially offset by lower income tax expense ($23.8 million). Higher lease operating expenses related to workovers in the Gulf of Mexico and ramp up of production from the Terra Nova field in Canada Offshore following the completion of the asset life extension project in the fourth quarter of 2023. Higher exploration costs were the result of dry hole expense for the previously suspended exploration costs for Hoffe Park #1 (Mississippi Canyon166) and additional costs related to Oso #1 (Atwater Valley 138) exploration well in the Gulf of Mexico. The Mississippi Canyon Block 166 lease will expire in 2024 and there are no plans for additional exploration activities. The Oso #1 (Atwater Valley 138) exploration well encountered non-commercial hydrocarbons in the fourth quarter of 2023 and operations finished in the first quarter of 2024. Lower income tax expense was the result of lower pre-tax income.
Current wording
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the six months ended June 30, 2024 was $272.4 million, a decrease of $34.1 million compared to the same period of 2023. Lower net income from continuing operations was largely driven by higher lease operating expenses ($99.6 million), higher impairment of assets ($34.5 million), and higher DD&A expense ($15.3 million). Decreases were partially offset by higher other income ($45.6 million), lower exploration expenses ($38.9 million), lower income tax expense ($26.0 million), and lower interest expense on long-term debt ($17.7 million). Higher lease operating expenses related to workover costs at Neidermeyer and were partially offset by lower production handling costs at the King’s Quay floating production facility in the Gulf of Mexico. Impairment costs related to the Calliope field were recorded in the first quarter of 2024. Higher other income related to foreign exchange gains and interest income on outstanding joint interest receivables. Exploration expense in the current period was primarily due to dry hole expenses recorded for the Orange #1 (Mississippi Canyon 216) non-operated exploratory well in the Gulf of Mexico, the previously suspended exploration costs for Hoffe Park #1 (Mississippi Canyon 166), and additional costs related to the Oso #1 (Atwater Valley 138) exploration well in the Gulf of Mexico. The Orange #1 (Mississippi Canyon 216) exploratory well encountered non-commercial hydrocarbons and was classified to dry hole expense in the second quarter of 2024. The Hoffe Park #1 (Mississippi Canyon 166) lease expired in 2024 and there are no plans for additional exploration activities. The Oso #1 (Atwater Valley 138) exploration well encountered non-commercial hydrocarbons in the fourth quarter of 2023 and operations finished in the first quarter of 2024. Lower income tax expense was driven by lower net income. Lower interest expense is driven by overall lower debt levels.
Previous wording
For the three months ended March 31, 2024, total hydrocarbon production was 176,671 barrels of oil equivalent per day, a decrease of 2% compared to the same period in 2023. The decrease was principally due to lower production in the Gulf of Mexico due to increased downtime for workovers, which was substantially offset by an increase in volumes at Tupper Montney from new well production and lower royalty rates and an increase in production from the Terra Nova field in Canada Offshore due to the restart of production.
Current wording
For the six months ended June 30, 2024 total hydrocarbon production was 182,259 barrels of oil equivalent per day, a decrease of 2% compared to the same period in 2023. The decrease was principally due to lower production in the U.S., primarily in the Gulf of Mexico due to downtime for workovers and timing of new wells, and in the Eagle Ford Shale due to a lower number of new wells on production in the current period. Decreases in the U.S. were substantially offset by increases in Canada at both Tupper Montney due to new wells online, and Terra Nova, which restarted production in late 2023.
Previous 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.
Current 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.
Previous wording
The following table contains the weighted average sales prices for the three-month periods ended March 31, 2024 and 2023.
Current wording
The following table contains the weighted average sales prices for the three-month and six-month periods ended June 30, 2024 and 2023.
Previous wording
The following table contains benchmark prices relevant to the Company for the three-month periods ended March 31, 2024 and 2023.
Current wording
The following table contains benchmark prices relevant to the Company for the three-month and six-month periods ended June 30, 2024 and 2023.
Previous wording
The following table contains hydrocarbons produced during the three-month periods ended March 31, 2024 and 2023. For further discussion on volumes, please see Revenues from Production section on page 26.
Current wording
The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2024 and 2023. For further discussion on volumes, please see “Revenues from Production” section on page 29.
Previous wording
Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. Sales of purchase natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 23.
Current wording
Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. Sales of purchased natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 26.
Previous wording
DD&A expense for the three months ended March 31, 2024 increased by $15.5 million, compared to the same period in 2023. Higher DD&A expense from U.S. E&P resulted from higher sales volumes from the Eagle Ford Shale assets and an overall increase in rates. Higher DD&A expense from Canada E&P was primarily the result of higher sales volumes from Tupper Montney and Terra Nova fields, partially offset by overall lower rates due to fewer sales volumes from Kaybob Duvernay and Placid Montney assets following the sale of a portion of non-core assets in the fourth quarter of 2023.
Current wording
DD&A expense for the six months ended June 30, 2024 increased by $15.4 million, compared to the same period in 2023. Higher DD&A expense from U.S. E&P resulted from higher rates in the Gulf of Mexico, partially offset by lower production. Higher DD&A expense for Canada Offshore and Onshore was primarily the result of increased production volumes.
Previous wording
Impairment of assets for the three months ended March 31, 2024 was $34.5 million and related to Calliope field in Mississippi Canyon in the Gulf of Mexico, as a result of operational issues that led to a reserve reduction. There were no impairments in the three months ended March 31, 2023.
Current wording
For the three months ended June 30, 2024, there were no impairments. For the six months ended June 30, 2024, the Company impaired assets for $34.5 million related to Calliope field in Mississippi Canyon in the Gulf of Mexico as a result of operational issues that led to a reserve reduction.
Previous wording
Income taxes for the three months ended March 31, 2024 decreased by $27.3 million, compared to the same period in 2023. Lower income taxes were primarily the result of lower pre-tax income.
Current wording
Income taxes for the three and six months ended June 30, 2024 decreased by $5.6 million and $32.8 million, respectively, compared to the same periods in 2023. Lower income taxes for each period, respectively, were primarily the result of Canada tax credits received in the current quarter, and lower year-to-date pre-tax income.
Previous wording
Corporate activities include interest expense and income, foreign exchange effects and corporate overhead not allocated to E&P.
Current wording
Corporate activities included interest expense and income, foreign exchange effects and corporate overhead not allocated to E&P.
Previous wording
Corporate activities reported a loss of $27.5 million for the three months ended March 31, 2024, a favorable variance of $1.2 million compared to the same period of 2023. The favorable variance was primarily due to foreign exchange gains ($10.9 million) and lower interest expense ($9.0 million), partially offset by increased selling and general expense ($15.7 million) and lower income tax benefits ($3.4 million) .
Current wording
Corporate activities reported a loss of $27.7 million for the three months ended June 30, 2024, a favorable variance of $18.9 million compared to the same period of 2023. The favorable variance was primarily due to foreign exchange gains ($13.2 million) and decreased interest expense ($8.8 million), partially offset by lower income tax benefits ($3.5 million). Lower interest expense for the current period was primarily due to lower overall debt levels. Lower income tax benefit was the result of lower pre-tax losses.
Previous wording
Interest charges are lower for the three months ended March 31, 2024, primarily due to lower overall debt levels. Higher selling and general expenses were a result of the timing of corporate donations and an increase in provisions for incentive awards. Lower income tax benefit was a result of lower pre-tax losses.
Current wording
Corporate activities reported a loss of $55.2 million for the six months ended June 30, 2024, a favorable variance of $20.0 million compared to the same period of 2023. The favorable variance was primarily due to foreign exchange gains ($24.1 million) and lower interest expense ($17.8 million), partially offset by increased selling and general expense ($15.7 million) and lower income tax benefits ($6.9 million). Lower interest expense for the current period was primarily due to lower overall debt levels. Higher selling and general expenses for the six months ended June 30, 2024 were primarily the result of the timing of corporate donations. Lower income tax benefit was the result of lower pre-tax losses.
Previous wording
Net cash provided by continuing operations activities for the three months ended March 31, 2024 was $119.0 million higher compared to the same period in 2023. The increase was primarily attributable to no contingent consideration payments related to prior Gulf of Mexico acquisitions in 2024 (2023: $124.0 million) and the timing of working capital settlements ($50.7 million), partially offset by higher lease operating expenses ($34.3 million) primarily related to workovers in the Gulf of Mexico. Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities. During the three months ended March 31, 2023, the Company paid a total of $171.7 million in contingent consideration, of which $124.0 million is shown in “Operating Activities” and $47.7 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.
Current wording
Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities. During the six months ended June 30, 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.
Previous wording
Net cash required by investing activities for the three months ended March 31, 2024 was $96.2 million lower compared to the same period in 2023. The decrease was due to lower property additions and dry hole costs ($96.2 million).
Current wording
Net cash required by investing activities for the six months ended June 30, 2024 was $177.9 million lower compared to the same period in 2023. The decrease was due to lower property additions and dry hole costs.
Previous wording
Lower capital expenditures in the three months ended March 31, 2024 compared to the same period of 2023 was primarily attributable to lower development expenditures at Eagle Ford Shale assets, partially offset by higher development expenditures at various Gulf of Mexico fields.
Current wording
Lower capital expenditures in the six months ended June 30, 2024 compared to the same period of 2023 was primarily attributable to lower exploration expenditures in the Gulf of Mexico, and lower development expenditures at Eagle Ford Shale, partially offset by higher development expenditures at various Gulf of Mexico fields.
Previous wording
Capital expenditures in 2024 primarily relate to development drilling and field development activities at Eagle Ford Shale assets ($53.4 million), development drilling and field development activities at Tupper Montney field ($47.8 million), development activities in the Gulf of Mexico, primarily related to Khaleesi, Mormont, Lucius and St. Malo fields ($106.4 million) and total exploration costs of $35.8 million. Total exploration costs in 2024 were in the Gulf of Mexico for the Orange #1 (Mississippi Canyon 216) and Ocotillo #1 (Mississippi Canyon 40) exploration wells and additional costs related to Oso #1 (Atwater Valley 138) exploration well which encountered non-commercial hydrocarbons in the fourth quarter of 2023 and finished operations in the first quarter of 2024.
Current wording
Total exploration costs in 2024 were in the Gulf of Mexico for the Orange #1 (Mississippi Canyon 216) exploration well, that encountered non-commercial hydrocarbons, the Ocotillo #1 (Mississippi Canyon 40) exploration well, and additional costs related to Oso #1 (Atwater Valley 138) exploration well, which encountered non-commercial hydrocarbons in the fourth quarter of 2023 and finished operations in the first quarter of 2024.
Previous wording
Net cash required by financing activities for the three months ended March 31, 2024 increased by $29.5 million compared to the same period in 2023. In 2024, the cash used in financing activities was principally for the repurchase of common shares ($50.0 million, excluding accrued excise tax), cash dividends to shareholders of $0.30 per share ($45.8 million), withholding tax on stock-based incentive awards ($25.3 million) and distributions to the noncontrolling interest in the Gulf of Mexico ($23.0 million). In 2023, there were payments of contingent consideration related to prior Gulf of Mexico acquisitions ($47.7 million) as discussed in the “Cash Provided by Operating Activities” section.
Current wording
Net cash required by financing activities for the six months ended June 30, 2024 increased by $157.7 million compared to the same period in 2023. In 2024, the cash used in financing activities was principally for the repurchase of common shares ($105.9 million), excluding accrued excise tax), cash dividends to shareholders of $0.60 per share ($91.5 million), withholding tax on stock-based incentive awards ($25.3 million), distributions to the noncontrolling interest in the Gulf of Mexico ($61.2 million), and debt repurchases of $50.0 million. In 2023, there were cash dividends to shareholders $85.9 million, withholding tax on stock-based incentive awards ($14.2 million), distributions to the noncontrolling interest in the Gulf of Mexico ($16.0 million), and contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Operating Activities” section.
Previous wording
At March 31, 2024, the Company had approximately $1.1 billion of liquidity consisting of $323.4 million in cash and cash equivalents and $796.3 million available on its committed senior unsecured RCF with a major banking consortium.
Current wording
At June 30, 2024 the Company had approximately $1.1 billion of liquidity consisting of $333.6 million in cash and cash equivalents and $796.3 million available on its committed senior unsecured RCF with a major banking consortium.
Previous wording
The Company’s $800 million senior unsecured RCF expires in November 2027 and as of March 31, 2024, the Company had no outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF. At March 31, 2024, the interest rate in effect on borrowings under the facility would have been 7.68%. At March 31, 2024, the Company was in compliance with all covenants related to the RCF.
Current wording
The Company’s $800 million senior unsecured RCF expires in November 2027 and as of June 30, 2024 the Company had no outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduce the borrowing capacity of the facility. At June 30, 2024 the interest rate in effect on borrowings under the facility would have been 7.69%. At June 30, 2024 the Company was in compliance with all covenants related to the RCF.
Previous wording
Cash and invested cash are maintained in several operating locations outside the U.S. As of March 31, 2024, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $98.1 million, the majority of which was held in Canada ($60.0 million), Mexico ($15.0 million) and the U.K. ($9.1 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Current wording
Cash and invested cash are maintained in several operating locations outside the U.S. As of June 30, 2024 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $67.8 million, the majority of which was held in Canada ($36.3 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Previous wording
At March 31, 2024, long-term debt of $1,328.7 million had increased by $0.4 million compared to December 31, 2023, primarily as a result of normal debt issuance cost amortization. The total of the fixed-rate notes had a weighted average maturity of 7.9 years and a weighted average coupon of 6.2%.
Current wording
At June 30, 2024 long-term debt of $1,279.3 million decreased by $49.0 million compared to December 31, 2023, primarily as a result of the open market repurchase of $50.0 million. The total of the fixed-rate notes had a weighted average maturity of 7.8 years and a weighted average coupon of 6.2%.
Previous wording
Murphy shareholders’ equity decreased by $58.8 million in 2024 primarily due to shares repurchased ($50.0 million, including excise tax), cash dividends paid ($45.8 million) and unrealized foreign currency translation losses ($35.5 million), partially offset by net income earned ($90.0 million). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 6 of this Form 10-Q report.
Current wording
Murphy shareholders’ equity decreased by $39.1 million in 2024 primarily due to shares repurchased ($106.5 million, including excise tax), cash dividends paid ($91.5 million) and unrealized foreign currency translation losses ($52.4 million), partially offset by net income earned ($217.7 million). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 6 of this Form 10-Q report.
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 also excludes certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.
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) and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income excludes certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.
Previous wording
The oil and gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the Results of Operations section discussing revenues, on page 26, higher average crude oil price during the first quarter of 2024 compared to same period in 2023, directly impacted the Company’s product sales revenue.
Current wording
The oil and gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the “Results of Operations” section discussing revenues, on page 29, higher average crude oil price during the second quarter of 2024, and lower average natural gas pricing compared to same period in 2023 directly impacted the Company’s product sales revenue.
Previous wording
Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company is observing higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.
Current wording
Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.
Previous wording
We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash flows. For the second quarter of 2024, production is expected to average between 176 and 184 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.
Current wording
We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash flows. For the third quarter of 2024, production is expected to average between 181.5 and 189.5 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.
Previous wording
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction. Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022. In 2023, the Company’s Board of Directors authorized a $300 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $600 million. As of March 31, 2024, the Company has $400 million remaining available to repurchase.
Current wording
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction. Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022 and August 8, 2024. In October 2023 and August 2024, the Company’s Board of Directors authorized an aggregate of $800 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $1.1 billion. On August 7, 2024 the Company’s Board of Directors approved a revision to the Capital Allocation Framework to enable the Company to move to the next phase (“Murphy 3.0”). Beginning in the third quarter of 2024, Murphy will allocate a minimum of 50 percent of adjusted free cash flow to shareholder returns, primarily through share buybacks. The remainder of adjusted free cash flow will be allocated to the balance sheet. Murphy continues to be committed to maintaining a $1.0 billion total long-term debt goal.
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022 and August 8, 2024.
Current report — wording carried from elsewhere
•On August 7, 2024 the Company’s Board of Directors authorized an increase to the share repurchase program of an additional $500 million, bringing the total amount allowed to be repurchased under the program to $1.1 billion
Current report — wording carried from elsewhere
There were no impairments in the three and six months ended June 30, 2023.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Exploration expenses for the three months ended March 31, 2024 increased by $34.1 million compared to the same period in 2023. Higher dry holes and previously suspended exploration costs primarily relate to the previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) and additional costs related to the Oso #1 (Atwater Valley 138) exploration well in the Gulf of Mexico. The Mississippi Canyon Block 166 lease will expire in 2024 and there are no plans for additional exploration activities. The Oso #1 (Atwater Valley 138) exploration well encountered non-commercial hydrocarbons in the fourth quarter of 2023 and finished operations in the first quarter of 2024.