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For the transition period from              to

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes  ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☒ Yes    ☐ No 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2023 was 156,155,341.

See Notes to Consolidated Financial Statements, page 7.

See Notes to Consolidated Financial Statements, page 7.

See Notes to Consolidated Financial Statements, page 7.

See Notes to Consolidated Financial Statements, page 7.

See Notes to Consolidated Financial Statements, page 7.

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas exploration and production company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States (U.S.) and Canada and conducts oil and natural gas exploration activities worldwide.

In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (LLOG) acquisition, we hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated as Murphy is not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2023, our maximum exposure to loss was $3.1 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.

INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2023 and December 31, 2022, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2023 and 2022, in conformity with U.S generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2022 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, 2023 are not necessarily indicative of future results.

Accounting Principles Adopted

Recent Accounting Pronouncements

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

For operated oil and natural gas production where the non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM) as prescribed by ASC 810-10-45.

U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.

Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load, based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.

Disaggregation of Revenue

The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.

For the three-month periods ended June 30, 2023, and 2022, the Company recognized $812.9 million and $1,196.2 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.

For the six-month periods ended June 30, 2023, and 2022, the Company recognized $1,652.8 million and $2,067.6 million, respectively, from total revenue from sales to customers, from sales of oil, natural gas liquids and natural gas.

Contract Balances and Asset Recognition

As of June 30, 2023, and December 31, 2022, receivables from contracts with customers, net of royalties and associated payables, on the balance sheets from continuing operations, were $197.4 million and $201.1 million, respectively.

Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any revenue contracts that have financing components as of June 30, 2023.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

Performance Obligations

The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.

As of June 30, 2023, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of more than 12 months starting at the inception of the contract:

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.

Exploratory Wells

Under Financial Accounting Standards Board guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

As of June 30, 2023, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $193.4 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2023 and 2022.

Capital additions of $47.7 million in 2023 are primarily related to Oso #1 well (Atwater Valley 138) and Longclaw GC 433 #1 in the Gulf of Mexico and LDV-4X in Vietnam. In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective. The Company plans to return to the well in the third quarter of 2023. Capitalized well costs charged to dry hole expense of $26.2 million for the six months ended June 30, 2023 are related to Cholula -1 EXP well in Mexico and Chinook #7 exploration well in the Gulf of Mexico. The preceding table excludes well costs of $70.3 million incurred and expensed directly to dry hole during the six months ended June 30, 2023, related to the Chinook #7 exploration well in the Gulf of Mexico.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.

Of the $184.9 million of exploratory well costs capitalized more than one year at June 30, 2023, $112.4 million was in Vietnam, $65.0 million was in the U.S., $4.8 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 

Impairments

There were no impairments in the six months ended June 30, 2023 or 2022.

Divestitures

On July 31, 2023 the Company entered into a purchase and sale agreement to sell a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash consideration of C$150 million. The transaction is anticipated to close in the third quarter of 2023, subject to closing conditions and adjustments. No gain or loss is anticipated in relation to this transaction. These assets did not meet the accounting criteria to be disclosed as held for sale as of June 30, 2023 and continue to be classified as “Property, plant and equipment” on the Company’s Consolidated Balance Sheets.

As of June 30, 2023, the Company had an $800 million revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on November 17, 2027, unless the outstanding principal amount of the Company’s 5.75% senior notes due 2025 (2025 Notes) as at February 15, 2025 exceeds $50.0 million, in which case, the RCF will expire on that date.

As of June 30, 2023, the Company had $248.7 million outstanding on the 2025 Notes. At June 30, 2023, the Company had no outstanding borrowings under the RCF and $30.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2023, the interest rate in effect on borrowings under the RCF would have been 7.74%. At June 30, 2023, the Company was in compliance with all covenants related to the RCF.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2024.

Additional disclosures regarding cash flow activities are provided below.

1 Excludes payable balances relating to mark-to-market of derivative instruments and contingent consideration relating to acquisitions.

The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.

A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the six-month periods ended June 30, 2023 and 2022 is shown in the following table.

1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.

The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

The Company has defined benefit pension plans that are noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans meet the requirements of local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2023 and 2022.

The components of net periodic benefit expense, other than the service cost, are recorded in “Other (expenses) income” in the Consolidated Statements of Operations.

During the six-month period ended June 30, 2023, the Company made contributions of $18.9 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2023 for the Company’s defined benefit pension and postretirement plans is anticipated to be $18.2 million.

The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of five million shares are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the Plan.

During the six months ended June 30, 2023, the Committee granted the following awards from the 2020 Long-Term Plan:

2020 Long-Term Incentive Plan

1 Performance based RSUs are scheduled to vest over a three year performance period.

2 Time based RSUs are generally scheduled to vest over three years from the date of grant.

3 Cash settled RSUs are generally scheduled to vest over three years from the date of grant.

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan) and the 2018 Stock Plan for Non-Employee Directors. All awards on or after May 12, 2021, were made under the 2021 NED Plan.

During the six months ended June 30, 2023, the Committee granted the following awards to Non-Employee Directors:

2021 Stock Plan for Non-Employee Directors

1 Non-employee directors time-based RSUs are scheduled to vest in February 2024.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding obligations, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the six-month period ended June 30, 2023.

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2023 and 2022. The following table reports the weighted-average shares outstanding used for these computations.

1 The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and six-month periods ended June 30, 2023 and 2022, the Company’s effective income tax rates were as follows:

The effective tax rate for the three-month period ended June 30, 2023, was above the U.S. statutory tax rate of 21% primarily due to several factors, including: no tax benefit applied to the pre-tax loss of the noncontrolling interest in MP GOM; U.S. state tax expense; stock-based compensation; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.

The effective tax rate for the three-month period ended June 30, 2022, was below the statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the six-month period ended June 30, 2023 was above the U.S. statutory tax rate of 21% primarily due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rate for the six-month period ended June 30, 2022 was below the statutory tax rate of 21% primarily due to no tax applied to the pre-tax income of the noncontrolling interest in MP GOM offset by exploration expenses in certain foreign jurisdictions in which no income tax benefit is currently available.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company has paid amounts into escrow, and may from time to time pay more amounts into escrow, in order to continue tax disputes with the relevant taxing authorities.

As of June 30, 2023, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2016. Following the sale in 2019, the Company has retained certain possible liabilities and rights to income tax receivables relating to the divested Malaysia business for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. 

Commodity Price Risks

During the second quarter of 2023, the Company did not have any outstanding crude oil derivative contracts.

During the second quarter of 2022, the Company had crude oil swaps and collar contracts. Under the swaps contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. Under the collar contracts, which also matured monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts required payments by the Company if the NYMEX average closing price was above the ceiling price or payments to the Company if the NYMEX average closing price was below the floor price.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at June 30, 2023 and 2022.

For the three-month and six-month periods ended June 30, 2023 and 2022, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.

ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. 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 Greenhouse Gas (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.

Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environment legal proceedings likely to exceed this $1.0 million threshold.

There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, the Inflation Reduction Act of 2022 contains provisions that impose fees for excess methane emissions from petroleum and natural gas facilities. In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S. economy by 2050. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. has since rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.

Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized and unrealized gains/losses on commodity price derivatives), interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.) and U.S. refining and marketing operations as discontinued operations for all periods presented.

1  Additional details about results of oil and natural gas operations are presented in the table on pages 27 and 28.

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2023 was $92.5 million, compared to $410.4 million in the in the second quarter of 2022, reflecting a decrease of $317.9 million. Lower net income from continuing operations was largely driven by lower revenues and other income ($286.5 million), increases in exploration expenses ($100.6 million) and higher lease operating expenses ($46.9 million), partially offset by lower income tax expense ($70.2 million). Lower revenues resulted from lower pricing, partially offset by higher sales volumes. Higher exploration costs were the result of dry hole expenses for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa and the expensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico. Increases in lease operating expenses were the result of higher sales volumes while lower income tax expense was the result of lower pre-tax income.

For the six months ended June 30, 2023, the Company reported net income from continuing operations of $306.5 million, compared to $345.5 million in the same period of 2022, reflecting a decrease of $39.0 million. Lower net income from continuing operations was largely driven by higher lease operating expenses ($110.1 million) and increases in exploration expenses ($63.3 million), partially offset by lower other operating expense ($125.9 million). Total revenues and other income were consistent period over period as higher sales volumes and no realized and unrealized losses on derivative instruments were offset by lower pricing for the six months ended June 30, 2023. Increased lease operating expenses relate to higher sales volumes and additional costs associated with workover and maintenance activities at the Gulf of Mexico operations. Higher exploration costs were the result of dry hole expense for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa, and the expensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico. Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico.

For the three months ended June 30, 2023, West Texas Intermediate (WTI) crude oil prices averaged approximately $73.78 per barrel (compared to $108.41 in the second quarter of 2022 and $76.13 in the first quarter of 2023). The average price for WTI in June of 2023 was approximately $70.27 per barrel, reflecting a 39% reduction from June of 2022 and a 4% reduction from the average price from March of 2023. The average price in July 2023 was $76.03 per barrel. As of close on August 1, 2023, the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were $80.68 and $76.93 per barrel, respectively.

For the three months ended June 30, 2023, the New York Mercantile Exchange (NYMEX) natural gas price per million British Thermal Units (MMBTU) averaged approximately $2.12 per barrel (compared to $7.39 in the second quarter of 2022 and $2.67 in the first quarter of 2023). The average price for NYMEX natural gas in June of 2023 was approximately $2.12 per barrel, reflecting a 72% reduction from June of 2022 and a 9% reduction from the average price from March of 2023. As of close on August 1, 2023, the NYMEX natural gas forward curve prices for the remainder of 2023 and 2024 were $2.95 and $3.45 per barrel, respectively.

For the three months ended June 30, 2023, the Company produced 191 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $362.3 million in capital expenditures (on a value of work done basis), which included $32.3 million in acquisition-related capital. Acquisition-related capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs and seismic data for Côte d’Ivoire in offshore Africa.

For the six months ended June 30, 2023, the Company produced 185 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $698.3 million in capital expenditures (on a value of work done basis), which included acquisition capital of $32.3 million. Acquisition capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs for Côte d’Ivoire in offshore Africa. 

During the three and six months ended June 30, 2023, crude oil and condensate, natural gas and natural gas liquids (NGL) volumes from continuing operations were higher than the comparable prior year periods. The increase in production volumes was primarily due to higher production from Khaleesi, Mormont, Samurai field development project, reflecting a full second quarter of production in 2023 (the project started in Q2 2022) and increased production from new wells added since the second quarter of 2022.

In addition, there were higher gas volumes at Tupper Montney related to new well production. For the three and six months ended June 30, 2023, revenue from production was 30% lower and 19% lower, respectively, compared to the same periods in 2022, primarily driven by the decrease in prices.

For the three months ended June 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $317.1 million in capital expenditures (on a value of work done basis), which included $46.5 million for an additional working interest in the Kodiak field in the Gulf of Mexico. The Company reported net income from continuing operations of $410.4 million for the three months ended June 30, 2022; this amount included after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $69.6 million and after-tax losses on contingent consideration of $25.1 million.

During the second quarter of 2022, the Company achieved first production at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico, with production flowing through the Murphy-operated King’s Quay floating production system.

In June 2022, the Company also acquired an additional 11.0% working interest (there is no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $46.5 million.

For the six months ended June 30, 2022, the Company produced 162 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $621.9 million in capital expenditures (on a value of work done basis), which included $46.5 million related to acquisition capital and $24.3 million related to the Cutthroat -1 exploration well in Brazil. The Company reported net income from continuing operations of $345.5 million for the six months ended June 30, 2022. This amount included after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration adjustments of $79.3 million and $102.3 million, respectively.

Murphy’s income (loss) by type of business is presented below.