MURPHY OIL CORP

Previous wording

Significant Company financial and operational highlights during the second quarter of 2024 were as follows:

Current wording

Significant Company financial and operational highlights during the third quarter of 2024 were as follows:

Previous wording

•Produced 187,847 barrels of oil equivalent per day (including NCI) during the quarter

Current wording

•Produced 191,273 barrels of oil equivalent per day (including NCI)

Previous wording

◦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 wording

•Repurchased $194.1 million ($196.2 million including excise taxes and fees) of common stock, or 5,374,191 shares, at an average price of $36.12 per share

Previous wording

Subsequent to the second quarter of 2024:

Current wording

Subsequent to the third quarter of 2024:

Previous wording

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 wording

For the three months ended September 30, 2024 total hydrocarbon production was 191,273 barrels of oil equivalent per day, a decrease of 8% compared to the third quarter of 2023. The decrease was principally due to lower production in the U.S., primarily in the Gulf of Mexico, due to workover activities and downtime, and in the Eagle Ford Shale, due primarily to the timing of new wells. Decreases in the U.S. were offset by increases in Canada at both Terra Nova, which restarted production in late 2023.

Previous 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.

Current wording

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2024 was $424.1 million, a decrease of $160.6 million compared to the same period of 2023. Lower net income from continuing operations was largely driven by lower revenues from production ($196.7 million), higher lease operating expenses ($129.2 million), and higher impairment of assets ($34.5 million). These were partially offset by lower income tax expense ($102.0 million), lower exploration expenses ($34.1 million), higher other income ($32.8 million), lower interest expense on long-term debt ($26.4 million), and lower transportation, gathering and processing expenses ($17.8 million). Lower revenues from production were primarily driven by downtime in the Gulf of Mexico and Eagle Ford Shale and lower natural gas prices, partially offset by higher year-to-date oil prices, higher production in Canada due to the restart of production at Terra Nova in late 2023, and well performance, combined with lower royalty rates at Tupper Montney. Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico and higher production activity in Canada at Terra Nova, partially offset by lower production handling (PHA) fees in the Gulf of Mexico. Impairment charges related to the Calliope field were recorded in the first quarter of 2024. The decrease in income tax expense primarily relates to lower income tax expenses driven by lower overall income, in addition to an income tax deduction for prior years’ Australia exploration spend. Exploration expense in the current period was primarily due to dry hole expense recorded for multiple wells in the Gulf of Mexico, including Sebastian #1 (Mississippi Canyon 387) and Orange #1 (Mississippi Canyon 216), additional costs related to the Oso #1 (Atwater Valley 138) well, 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 interest expense was due to lower debt levels and lower transportation, gathering and processing expenses related to lower production in the U.S.

Previous 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.

Current wording

For the nine months ended September 30, 2024 total hydrocarbon production was 185,286 barrels of oil equivalent per day, a decrease of 4% 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 in the Eagle Ford Shale, due to timing of new wells. Decreases in the U.S. were partially 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

The following table contains the weighted average sales prices for the three-month and six-month periods ended June 30, 2024 and 2023.

Current wording

The following table contains the weighted average sales prices for the three-month and nine-month periods ended September 30, 2024 and 2023.

Previous 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.

Current wording

The following table contains benchmark prices relevant to the Company for the three-month and nine-month periods ended September 30, 2024 and 2023.

Previous 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.

Current wording

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2024 and 2023. For further discussion on volumes, please see “Revenues from Production” section on page 29.

Previous wording

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 wording

Revenues from production for the nine months ended September 30, 2024 decreased $196.7 million compared to the same period in 2023. Lower revenue was driven primarily by workover activities, downtime and timing of new wells 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 production restarting at Terra Nova in late 2023, and higher oil prices.

Previous wording

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 wording

For the three months ended September 30, 2024 lease operating expenses increased by $29.5 million and TGP expenses decreased by $14.0 million compared to the same period in 2023. Higher lease operating expenses were due to workover activity in the Gulf of Mexico and higher production at Terra Nova and were partially offset by lower PHA fees in the Gulf of Mexico. Lower TGP expenses during the quarter were a result of lower production volumes in the Gulf of Mexico.

Previous wording

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 wording

For the nine months ended September 30, 2024, lease operating expenses increased by $129.2 million and TGP expenses decreased by $17.8 million compared to the same period in 2023. Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico, primarily at the Neidermeyer field, and higher production at Terra Nova, and were partially offset by lower PHA fees in the Gulf of Mexico. Lower TGP expenses resulted primarily from lower production volumes in the Gulf of Mexico.

Previous wording

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 wording

DD&A expense for the three months ended September 30, 2024 decreased by $12.6 million compared to the same period in 2023. The decrease is primarily due to lower volumes in the Gulf of Mexico and at Eagle Ford Shale, partially offset by higher volumes in Canada Offshore and Onshore and higher rates in the U.S. due to development drilling.

Previous 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.

Current wording

For the three months ended September 30, 2024, there were no impairments. For the nine months ended September 30, 2024, the Company impaired assets for $34.5 million, related to the Calliope field in the Gulf of Mexico, as a result of operational issues that led to a reserve reduction.

Previous wording

There were no impairments in the three and six months ended June 30, 2023.

Current wording

There were no impairments in the three and nine months ended September 30, 2023.

Previous wording

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 wording

Exploration expenses for the three months ended September 30, 2024 increased by $4.8 million compared to the prior year, primarily as a result of higher geological and geophysical costs in the Gulf of Mexico in the current period. Dry hole costs in the current period represented costs associated with the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the U.S. Gulf of Mexico that encountered non-commercial hydrocarbons in the third quarter of 2024. In the third quarter of 2023, we recorded dry hole costs related to the Chinook #7 (Walker Ridge 425) exploration well in the U.S. Gulf of Mexico.

Previous wording

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 wording

Exploration expenses for the nine months ended September 30, 2024 decreased by $34.1 million compared to the same period in 2023. In the current period, dry hole costs were recorded for the Sebastian #1 (Mississippi Canyon 387) operated exploration well, 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.

Previous wording

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 wording

Other expenses for the three and nine months ended September 30, 2024 decreased by $1.1 million and $33.7 million, respectively, compared to the same periods in 2023. For the three months ended September 30, 2024 the decrease is primarily due to the absence of other operating expenses in Canada related to the Terra Nova life extension project. For the nine months ended September 30, 2024 the decrease was due to a combination of interest income received and a favorable state tax settlement related to U.S. Onshore activities.

Previous 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.

Current wording

Income taxes for the three and nine months ended September 30, 2024 decreased by $75.9 million and $108.7 million, respectively, compared to the same periods in 2023. Lower income taxes for each period, respectively, were primarily the result of lower year-to-date pre-tax income, and an income tax deduction for prior years’ Australia exploration spend.

Previous 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.

Current wording

Corporate activities reported a loss of $33.7 million for the three months ended September 30, 2024, an unfavorable variance of $3.6 million compared to the same period of 2023. The unfavorable variance was primarily due to unrealized foreign exchange losses ($14.0 million), partially offset by decreased interest expense ($8.8 million). Lower interest expense for the current period was primarily due to lower overall debt levels.

Previous 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.

Current wording

Corporate activities reported a loss of $88.9 million for the nine months ended September 30, 2024, a favorable variance of $16.5 million compared to the same period of 2023. The favorable variance was primarily due to lower interest expense ($26.6 million) and unrealized foreign exchange gains ($10.1 million) and was partially offset by increased selling and general expense ($15.6 million) and lower income tax benefits ($6.7 million). Lower interest expense for the current period was primarily due to lower overall debt levels. Higher selling and general expenses for the nine months ended September 30, 2024 were primarily attributable to timing of corporate donations. Lower income tax benefit was the result of lower pre-tax losses.

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. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.

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 the New RCF. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company 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.

Previous 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.

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 nine months ended September 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 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.

Current wording

Net cash required by investing activities for the nine months ended September 30, 2024 was $88.9 million lower compared to the same period in 2023. The decrease was due to lower property additions and dry hole costs ($169.0 million), partially offset by cash inflows from the sale of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets Kaybob properties ($102.9 million) in 2023.

Previous 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.

Current wording

Lower capital expenditures in the nine months ended September 30, 2024 compared to the same period of 2023 was primarily attributable to lower exploration expenditures in the Gulf of Mexico, lower field development costs due to the Terra Nova asset life extension project ending in 2023, and lower development drilling costs at Eagle Ford Shale and Tupper Montney, 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 ($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 wording

Capital expenditures in 2024 primarily relate to development drilling and field development activities at Eagle Ford Shale ($246.8 million), at the Khaleesi, Mormont and Samurai fields, and the non-operated St. Malo and Lucius fields in the Gulf of Mexico ($235.7 million), and at Tupper Montney ($75.4 million), Kaybob Duvernay

Previous 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.

Current wording

Exploration costs in 2024 were primarily comprised of activities in the Gulf of Mexico related to the Sebastian #1 (Mississippi Canyon 387), Orange #1 (Mississippi Canyon 216), and Oso #1 (Atwater Valley 138) exploration wells. Sebastian #1 and Orange #1 encountered non-commercial hydrocarbons during 2024. Oso #1 encountered non-commercial hydrocarbons in 2023, and operations completed in 2024. Additional exploratory costs relate to the Ocotillo #1 (Mississippi Canyon 40) exploration well.

Previous 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.

Current wording

Net cash required by financing activities for the nine months ended September 30, 2024 increased by $61.4 million compared to the same period in 2023. In 2024, the cash used in financing activities was principally for the repurchase of common shares ($300.1 million), cash dividends to shareholders of $0.90 per share ($136.2 million), withholding tax on stock-based incentive awards ($25.3 million), distributions to the noncontrolling interest in the Gulf of Mexico ($96.6 million), and debt repurchases of $50.0 million. In 2023, there were debt repurchases ($248.7 million), cash dividends to shareholders ($128.7 million), the repurchase of common shares ($75.0 million), withholding tax on stock-based incentive awards ($14.2 million), distributions to the noncontrolling interest in the Gulf of Mexico ($20.1 million), and contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Continuing Operations Activities” section.

Previous 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.

Current wording

At September 30, 2024 the Company had approximately $1.1 billion of liquidity consisting of $271.2 million in cash and cash equivalents and $799.6 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 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.

Current wording

The Company’s $800.0 million senior unsecured RCF was set to expire in November 2027 and as of September 30, 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 facility. At September 30, 2024 the interest rate in effect on borrowings under the facility would have been 7.20%. At September 30, 2024 the Company was in compliance with all covenants related to the RCF. Subsequent to quarter end, on October 7, 2024, the Company entered into a New RCF, a credit agreement governing a $1,200.0 million senior unsecured revolving credit facility with a maturity date in October 2029, which replaced the prior RCF.

Previous 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.

Current wording

Cash and invested cash are maintained in several operating locations outside the U.S. As of September 30, 2024 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $101.6 million, the majority of which was held in Canada ($72.3 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

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 wording

As of September 30, 2024 net working capital decreased by $160.9 million compared to December 31, 2023. The decrease was primarily attributable to lower accounts receivable ($80.9 million), lower cash balance ($45.9 million), and higher operating lease liabilities ($45.5 million), and was partially offset by lower accounts payable ($17.1 million).

Previous wording

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 wording

Lower accounts receivable was primarily due to lower revenues. Higher operating lease liabilities were primarily attributable to the current portion of lease extensions recorded during the period related to a drill ship in the

Previous 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%.

Current wording

At September 30, 2024 long-term debt of $1,279.3 million decreased by $49.1 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 7.5 years and a weighted average coupon of 6.2%.

Previous 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.

Current wording

Murphy shareholders’ equity decreased by $113.1 million in 2024, primarily due to shares repurchased ($302.7 million, including excise tax), cash dividends paid ($136.2 million) and unrealized foreign currency translation losses ($34.6 million), partially offset by net income earned ($356.8 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 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.

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, lower average crude oil and natural gas pricing during the third quarter of 2024 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 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.

Current wording

Similar to the overall inflation 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 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.

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 fourth 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 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.

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. 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.