EXHIBIT 99.1
MURPHY OIL CORPORATION ANNOUNCES FOURTH QUARTER AND FULL YEAR 2023 RESULTS, PRELIMINARY YEAR-END 2023 RESERVES, 2024 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Accomplished 2023 Debt Reduction Goal of $500 Million,
Repurchased $150 Million of Shares in Accordance With Capital Allocation Framework,
Increased Dividend 9 Percent Annualized in 2024,
Achieved 139 Percent Total Reserve Replacement Ratio
With Preliminary Proved Reserves of 724 MMBOE
HOUSTON, Texas, January 25, 2024 – Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the fourth quarter ended December 31, 2023, including net income attributable to Murphy of $116 million, or $0.75 net income per diluted share. Excluding discontinued operations and other items affecting comparability between periods, adjusted net income attributable to Murphy was $140 million, or $0.90 adjusted net income per diluted share.
For full year 2023, the company recorded net income attributable to Murphy of $662 million, or $4.22 net income per diluted share. Murphy reported adjusted net income, which excludes both the results of discontinued operations and other items affecting comparability between periods, of $709 million, or $4.52 adjusted net income per diluted share.
Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude noncontrolling interest (NCI). 1
Highlights for the fourth quarter include:
•Produced 185 thousand barrels of oil equivalent per day (MBOEPD), with 94 thousand barrels of oil per day (MBOPD), or 51 percent oil volumes
•Retired $250 million of senior notes due 2027, 2028 and 2029 through a tender offer
•Repurchased $75 million, or 1.7 million shares, at an average price of $43.42 per share
•Named apparent high bidder on eight exploration blocks in the Gulf of Mexico Federal Lease Sale 261
•Acquired 8 percent working interest in the non-operated Zephyrus discovery in the Gulf of Mexico for $13 million after closing adjustments
•Resumed operations at the non-operated Terra Nova field in offshore Canada with production expected to ramp up through first quarter 2024
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Highlights for full year 2023 include:
•Achieved $500 million debt reduction goal for 2023, resulting in $1.7 billion of total debt reduction and $84 million in annual interest expense savings since year-end 2020
•Repurchased $150 million of shares with $450 million remaining under the share repurchase authorization
•Increased quarterly cash dividend by 10 percent to $0.275 per share, or $1.10 per share annualized
•Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico
•Sanctioned the Lac Da Vang field development project in Vietnam
•Enhanced exploration portfolio with signing production sharing contracts for five blocks in Côte d’Ivoire
•Produced 186 MBOEPD with 98 MBOPD, or 52 percent oil volumes
•Realized 139 percent total reserve replacement with nearly 11-year reserve life and 724 million barrels of oil equivalent (MMBOE) preliminary total proved reserves at year-end 2023
•Ranked in top quartile of ISS Governance QualityScore in 2023
Subsequent to the fourth quarter:
•Announced an additional 9 percent increase of the quarterly cash dividend to $0.30 per share, or $1.20 per share annualized for 2024
“We had a strong year of production and excellent execution, generating ample free cash flow to advance our capital allocation framework. This allowed us to return $150 million to shareholders through buybacks and retire $500 million of debt, resulting in a nearly 60 percent decrease in debt since year-end 2020,” said Roger W. Jenkins, President and Chief Executive Officer. “Our ongoing financial stewardship has given us momentum going into 2024, beginning with an increase to our longstanding dividend and restoring it to its 2016 level.”
FOURTH QUARTER 2023 RESULTS
The company recorded net income attributable to Murphy of $116 million, or $0.75 net income per diluted share, for the fourth quarter 2023. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $140 million, or $0.90 per diluted share for the same period. Adjustments to net income totaled $28 million before tax. Details for fourth quarter results and an adjusted net income reconciliation can be found in the attached schedules.
Earnings before interest, taxes, depreciation and amortization (EBITDA) attributable to Murphy were $375 million. Earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) attributable to Murphy were $457 million. Adjusted EBITDA attributable to Murphy was $414 million. Adjusted EBITDAX attributable to Murphy was $496 million.
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Reconciliations for fourth quarter EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX can be found in the attached schedules.
Fourth quarter production averaged 185 MBOEPD and included 51 percent oil volumes, or 94 MBOPD. Production for the quarter was in-line with guidance, with slightly lower Gulf of Mexico and Eagle Ford Shale production partially offset by lower realized royalty rates in the Tupper Montney asset.
Accrued capital expenditures (CAPEX) for fourth quarter 2023 totaled $219 million, excluding NCI and acquisition-related CAPEX. Details for fourth quarter production and CAPEX can be found in the attached schedules.
FULL YEAR 2023 RESULTS
The company recorded net income attributable to Murphy of $662 million, or $4.22 net income per diluted share, for full year 2023. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $709 million, or $4.52 per diluted share for the same period. Adjustments to net income were primarily attributable to a $17 million write-off of a previously suspended exploration well and $17 million of asset retirement obligation losses, with the remainder totaling $18 million before tax. Details for full year 2023 results and an adjusted net income reconciliation can be found in the attached schedules.
EBITDA attributable to Murphy was $1.8 billion. EBITDAX attributable to Murphy was $2.0 billion. Adjusted EBITDA attributable to Murphy was $1.9 billion. Adjusted EBITDAX attributable to Murphy was $2.1 billion. Reconciliations for full year 2023 EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX can be found in the attached schedules.
Production for full year 2023 averaged 186 MBOEPD and included 52 percent oil volumes, or 98 MBOPD. Accrued CAPEX for full year 2023 totaled $1,008 million, excluding NCI and $60 million of acquisition-related CAPEX. Details for full year 2023 production and CAPEX can be found in the attached schedules.
CAPITAL ALLOCATION FRAMEWORK
Murphy had approximately $1.1 billion of liquidity on December 31, 2023, with no borrowings on the $800 million senior unsecured credit facility and $317 million of cash and cash equivalents, inclusive of NCI.
In 2023, Murphy executed $500 million of debt reduction transactions through the redemption of the remaining $250 million of senior notes due 2025, as well as the aggregate tender offer of $250 million of senior notes due 2027, 2028 and 2029.
At the end of the fourth quarter, Murphy’s total debt was reduced to $1.3 billion, and consisted of long-term, fixed-rate notes with a weighted average maturity of 8.1 years and a weighted average coupon of 6.2 percent.
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During the fourth quarter, Murphy repurchased $75 million, or 1.7 million shares, at an average price of $43.42 per share. This brings the 2023 total share repurchases to $150 million, or 3.4 million shares, at an average price of $43.96 per share, reflecting a 2 percent total reduction in share count for the year. As of year-end 2023, Murphy had $450 million remaining under the share repurchase authorization and 152.7 million shares outstanding.
“I am pleased our ongoing debt reduction efforts are enhancing our balance sheet and extending our debt maturity profile, with the next tranche of senior notes not due until December 2027,” said Jenkins. “Since announcing our capital allocation framework in August 2022, we have reduced long-term debt by approximately $950 million, repurchased $150 million of shares and increased the quarterly dividend by 20 percent. This is an incredible accomplishment and reflects Murphy’s steady commitment to enhance shareholder value.”
YEAR-END 2023 PROVED RESERVES
After producing 68 MMBOE for the year, Murphy’s preliminary year-end 2023 proved reserves were 724 MMBOE, consisting of 36 percent oil and 41 percent liquids. Total reserve replacement was 139 percent in 2023.
The company maintained a consistent reserve life of nearly 11 years with 57 percent proved developed reserves.
2023 Proved Reserves – Preliminary * | |||||||||||||||||
Category | Net Oil (MMBBL) | Net NGLs (MMBBL) | Net Gas (BCF) | Net Equiv. (MMBOE) | |||||||||||||
Proved Developed (PD) | 175 | 25 | 1,275 | 413 | |||||||||||||
Proved Undeveloped (PUD) | 87 | 12 | 1,276 | 311 | |||||||||||||
Total Proved | 262 | 37 | 2,551 | 724 | |||||||||||||
* Proved reserves exclude NCI and are based on preliminary year-end 2023 third-party audited volumes using SEC pricing. | |||||||||||||||||
OPERATIONS SUMMARY
Onshore
In the fourth quarter of 2023, the onshore business produced approximately 100 MBOEPD, which included 30 percent liquids volumes.
Eagle Ford Shale – Fourth quarter production averaged 31 MBOEPD with 71 percent oil volumes and 86 percent liquids volumes. Three non-operated wells were brought online in Tilden during the quarter as planned.
Tupper Montney – Natural gas production averaged 386 million cubic feet per day (MMCFD) in the fourth quarter, with no new wells brought online.
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Kaybob Duvernay – During the fourth quarter, production averaged 4 MBOEPD with 69 percent liquids volumes.
Offshore
Excluding NCI, in the fourth quarter of 2023, the offshore business produced approximately 84 MBOEPD, which included 82 percent oil.
Gulf of Mexico – Production averaged approximately 81 MBOEPD, consisting of 81 percent oil during the fourth quarter. As planned, Murphy brought online the Dalmatian #1 (Desoto Canyon 90) well and drilled and completed the Marmalard #3 (Mississippi Canyon 255) well during the quarter.
Canada – In the fourth quarter, production averaged nearly 4 MBOEPD, consisting of 100 percent oil. The asset life extension project was completed for the non-operated Terra Nova floating, production, storage and offloading vessel, and production from the field resumed during the quarter with volumes expected to ramp up over the coming months.
EXPLORATION
Gulf of Mexico – During the quarter, Murphy concluded drilling the Oso #1 (Atwater Valley 138) exploration well. The well encountered non-commercial hydrocarbons and has been plugged and abandoned. Approximately $62 million of the net well cost before tax was expensed in the fourth quarter. Murphy, as operator, holds a 33.34 percent working interest in the well.
2024 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
The 2024 CAPEX plan is expected to be in the range of $920 million to $1.02 billion. Full year 2024 production is expected to be in the range of 180 to 188 MBOEPD, consisting of approximately 96 MBOPD oil and 106 MBOEPD liquids volumes, equating to 52 percent oil and 58 percent liquids volumes, respectively. This forecast includes approximately 2 MBOEPD of assumed annualized Gulf of Mexico storm downtime and accounts for the 2023 divestiture of 1.5 MBOEPD from non-core onshore Canadian assets.
Production for first quarter 2024 is estimated to be in the range of 163 to 171 MBOEPD with 89 MBOPD, or 53 percent, oil volumes. This range is impacted by 13 MBOEPD of total Gulf of Mexico downtime, as well as 2 MBOEPD of onshore downtime. Gulf of Mexico downtime in the first quarter includes 6 MBOEPD associated with wells currently offline that are scheduled for workovers and will return to production in the first half of this year. Also included is 5 MBOEPD for planned facility and downstream maintenance, as well as 2 MBOEPD of downtime to repair damaged subsea equipment in the Mormont field. Both production and CAPEX guidance ranges exclude Gulf of Mexico NCI.
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2024 CAPEX by Quarter ($ MMs) | |||||||||||||||||
1Q 2024E | 2Q 2024E | 3Q 2024E | 4Q 2024E | FY 2024E | |||||||||||||
$285 | $265 | $270 | $150 | $970 | |||||||||||||
Accrual CAPEX, based on midpoint of guidance range and excluding NCI.
The table below illustrates the capital allocation by area.
2024 Capital Expenditure Guidance | ||||||||
Area | Total CAPEX $ MMs | Percent of Total CAPEX | ||||||
Onshore | ||||||||
Eagle Ford Shale | $320 | 33 | ||||||
Kaybob Duvernay / Tupper Montney | $130 | 13 | ||||||
Offshore | ||||||||
Gulf of Mexico | $300 | 31 | ||||||
Hibernia / Terra Nova | $25 | 3 | ||||||
Other Offshore | $45 | 5 | ||||||
Exploration | ||||||||
Exploration | $120 | 12 | ||||||
Other | ||||||||
Other | $30 | 3 | ||||||
Onshore
Approximately $320 million of Murphy’s 2024 CAPEX is allocated to the Eagle Ford Shale, with approximately $240 million designated to drill 30 and bring online 19 operated wells, as well as drill 23 and bring online 18 non-operated wells. The remaining $80 million will support field development.
Murphy plans to spend $130 million of its 2024 CAPEX in Canada onshore. Approximately $65 million is allocated to the Tupper Montney to drill 9 and bring online 13 operated wells, with $35 million allocated to the Kaybob Duvernay to drill 4 and bring online 3 operated wells. The remaining $30 million will support field development in both areas.
The table below details the 2024 onshore well delivery plan by quarter.
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2024 Onshore Wells Online | |||||||||||||||||
1Q 2024 | 2Q 2024 | 3Q 2024 | 4Q 2024 | 2024 Total | |||||||||||||
Eagle Ford Shale | - | 7 | 12 | - | 19 | ||||||||||||
Kaybob Duvernay | - | 3 | - | - | 3 | ||||||||||||
Tupper Montney | - | 13 | - | - | 13 | ||||||||||||
Non-Op Eagle Ford Shale | 4 | - | 4 | 10 | 18 | ||||||||||||
Note: All well counts are shown gross. Eagle Ford Shale non-operated working interest averages 41 percent.
Offshore
Murphy plans to spend approximately $300 million of its 2024 CAPEX in the Gulf of Mexico for development drilling and field development projects. This plan includes operated and non-operated subsea tiebacks throughout the year, as well as advancing the non-operated St. Malo waterflood project ahead of its startup in 2024.
Murphy has allocated approximately $25 million of CAPEX to Canada offshore in 2024, with the majority designated for non-operated Hibernia development drilling.
Approximately $45 million of CAPEX has been allocated to other offshore development in 2024, primarily for initial Lac Da Vang field development activities in Vietnam.
Exploration
The company has allocated $120 million to its 2024 exploration program, which includes drilling two exploration wells in Vietnam and two exploration wells in the Gulf of Mexico.
Other
Other capital of approximately $30 million, or 3 percent of CAPEX, consists of capitalized interest costs and corporate CAPEX.
“We are positioned for another great year at Murphy as we continue to Delever, Execute, Explore, Return. With our consistent capital discipline, I look forward to reaching our long-term debt goal of $1.0 billion while continuing to reward shareholders through dividend increases and share repurchases,” said Jenkins.
Detailed guidance for the first quarter and full year 2024 is contained in the attached schedules.
FIXED PRICE FORWARD SALES CONTRACTS
Murphy maintains fixed price forward sales contracts in Canada to lessen its dependence on variable AECO prices. These contracts are for physical delivery of natural gas volumes at a fixed price, with no mark-to-market income adjustments. Details for the current fixed price contracts can be found in the attached schedules.
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CONFERENCE CALL AND WEBCAST SCHEDULED FOR JANUARY 25, 2024
Murphy will host a conference call to discuss fourth quarter 2023 financial and operating results on Thursday, January 25, 2024, at 9:00 a.m. EST. The call can be accessed either via the Internet through the events calendar on the Murphy Oil Corporation Investor Relations website at http://ir.murphyoilcorp.com or via telephone by dialing toll free 1-888-886-7786, reservation number 98175352. For additional information, please refer to the Fourth Quarter 2023 Earnings Presentation available under the News and Events section of the Investor Relations website.
FINANCIAL DATA
Summary financial data and operating statistics for fourth quarter 2023, with comparisons to the same period from the previous year, are contained in the attached schedules. Additionally, a schedule indicating the impacts of items affecting comparability of results between periods, a reconciliation of EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX between periods, as well as guidance for the first quarter and full year 2024, are also included.
1In accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this news release, but not the accompanying schedules, exclude the NCI, thereby representing only the amounts attributable to Murphy.
CAPITAL ALLOCATION FRAMEWORK
This news release contains references to the company’s capital allocation framework and adjusted free cash flow. As previously disclosed, the capital allocation framework defines Murphy 1.0 as when long-term debt exceeds $1.8 billion. At such time, adjusted free cash flow is allocated to long-term debt reduction while the company continues to support the quarterly dividend. The company reaches Murphy 2.0 when long-term debt is between $1.0 billion and $1.8 billion. At such time, approximately 75 percent of adjusted free cash flow is allocated to debt reduction, with the remaining 25 percent distributed to shareholders through share buybacks and potential dividend increases. When long-term debt is at or below $1.0 billion, the company is in Murphy 3.0 and begins allocating 50 percent of adjusted free cash flow to the balance sheet, with a minimum of 50 percent of adjusted free cash flow allocated to share buybacks and potential dividend increases.
Adjusted free cash flow is defined as cash flow from operations before working capital change, less capital expenditures, distributions to NCI and projected payments, quarterly dividend and accretive acquisitions.
ABOUT MURPHY OIL CORPORATION
As an independent oil and natural gas exploration and production company, Murphy Oil Corporation believes in providing energy that empowers people by doing right always, staying with it and thinking beyond possible. Murphy challenges the norm, taps into its strong legacy and uses its foresight and financial discipline to deliver inspired energy solutions. Murphy sees a future where it is an industry leader who is positively impacting lives for the next 100 years and
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beyond. Additional information can be found on the company’s website at www.murphyoilcorp.com.
FORWARD-LOOKING STATEMENTS
This news release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the company’s future operating results or activities and returns or the company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the company; therefore, we encourage investors, the media, business partners and others interested in the company to review the
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information we post on our website. The information on our website is not part of, and is not incorporated into, this news release. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
NON-GAAP FINANCIAL MEASURES
This news release contains certain non-GAAP financial measures that management believes are useful tools for internal use and the investment community in evaluating Murphy Oil Corporation’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry. Not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with GAAP and should therefore be considered only as supplemental to such GAAP financial measures. Please see the attached schedules for reconciliations of the differences between the non-GAAP financial measures used in this news release and the most directly comparable GAAP financial measures.
RESERVE REPORTING TO THE SECURITIES EXCHANGE COMMISSION
The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use certain terms in this news release, such as “resource”, “gross resource”, “recoverable resource”, “net risked PMEAN resource”, “recoverable oil”, “resource base”, “EUR” or “estimated ultimate recovery” and similar terms that the SEC’s rules prohibit us from including in filings with the SEC. The SEC permits the optional disclosure of probable and possible reserves; however, we have not disclosed the company’s probable and possible reserves in our filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Annual Report on Form 10-K filed with the SEC and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com.
Investor Contacts:
InvestorRelations@murphyoilcorp.com
Kelly Whitley, 281-675-9107
Megan Larson, 281-675-9470
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MURPHY OIL CORPORATION
SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | 834,683 | 936,715 | $ | 3,376,639 | 4,038,451 | |||||||||||||||||
| Sales of purchased natural gas | 7,587 | 49,404 | 72,215 | 181,689 | |||||||||||||||||||
| Total revenue from sales to customers | 842,270 | 986,119 | 3,448,854 | 4,220,140 | |||||||||||||||||||
| (Loss) on derivative instruments | — | (11,756) | — | (320,410) | |||||||||||||||||||
| Gain on sale of assets and other income | 1,928 | 856 | 11,293 | 32,932 | |||||||||||||||||||
| Total revenues and other income | 844,198 | 975,219 | 3,460,147 | 3,932,662 | |||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 196,713 | 196,455 | 784,391 | 679,342 | |||||||||||||||||||
| Severance and ad valorem taxes | 7,645 | 9,672 | 42,787 | 57,012 | |||||||||||||||||||
| Transportation, gathering and processing | 57,677 | 60,492 | 232,985 | 212,711 | |||||||||||||||||||
| Costs of purchased natural gas | 4,289 | 46,733 | 51,682 | 171,991 | |||||||||||||||||||
| Exploration expenses, including undeveloped lease amortization | 82,287 | 60,989 | 234,776 | 133,197 | |||||||||||||||||||
| Selling and general expenses | 42,908 | 41,114 | 117,306 | 131,121 | |||||||||||||||||||
| Depreciation, depletion and amortization | 212,772 | 202,316 | 861,602 | 776,817 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,863 | 11,518 | 46,059 | 46,243 | |||||||||||||||||||
| Other operating expense | 25,197 | 21,792 | 46,530 | 137,518 | |||||||||||||||||||
| Total costs and expenses | 641,352 | 651,081 | 2,418,118 | 2,345,952 | |||||||||||||||||||
| Operating income from continuing operations | 202,846 | 324,138 | 1,042,029 | 1,586,710 | |||||||||||||||||||
| Other loss | |||||||||||||||||||||||
| Other (loss) income | (9,631) | (6,804) | (8,587) | 14,310 | |||||||||||||||||||
| Interest expense, net | (23,678) | (34,657) | (112,373) | (150,759) | |||||||||||||||||||
| Total other loss | (33,309) | (41,461) | (120,960) | (136,449) | |||||||||||||||||||
| Income from continuing operations before income taxes | 169,537 | 282,677 | 921,069 | 1,450,261 | |||||||||||||||||||
| Income tax expense | 29,108 | 61,890 | 195,921 | 309,464 | |||||||||||||||||||
| Income from continuing operations | 140,429 | 220,787 | 725,148 | 1,140,797 | |||||||||||||||||||
| Loss from discontinued operations, net of income taxes | (723) | (162) | (1,467) | (2,078) | |||||||||||||||||||
| Net income including noncontrolling interest | 139,706 | 220,625 | 723,681 | 1,138,719 | |||||||||||||||||||
| Less: Net income attributable to noncontrolling interest | 23,421 | 21,227 | 62,122 | 173,672 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO MURPHY | $ | 116,285 | 199,398 | $ | 661,559 | 965,047 | |||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | 0.76 | 1.28 | $ | 4.27 | 6.23 | |||||||||||||||||
| Discontinued operations | — | — | (0.01) | (0.01) | |||||||||||||||||||
| Net income | $ | 0.76 | 1.28 | $ | 4.26 | 6.22 | |||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | 0.75 | 1.26 | $ | 4.23 | 6.14 | |||||||||||||||||
| Discontinued operations | — | — | (0.01) | (0.01) | |||||||||||||||||||
| Net income | $ | 0.75 | 1.26 | $ | 4.22 | 6.13 | |||||||||||||||||
| Cash dividends per common share | $ | 0.275 | 0.250 | $ | 1.100 | 0.825 | |||||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | 153,754 | 155,460 | 155,234 | 155,277 | |||||||||||||||||||
| Diluted | 155,289 | 157,675 | 156,646 | 157,475 | |||||||||||||||||||
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Operating Activities | |||||||||||||||||||||||
| Net income including noncontrolling interest | $ | 139,706 | 220,625 | $ | 723,681 | 1,138,719 | |||||||||||||||||
| Adjustments to reconcile net income to net cash provided by continuing operations activities | |||||||||||||||||||||||
| Depreciation, depletion and amortization | 212,772 | 202,316 | 861,602 | 776,817 | |||||||||||||||||||
| Deferred income tax expense | 27,719 | 78,974 | 179,823 | 286,079 | |||||||||||||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | 61,970 | 46,861 | 169,795 | 82,085 | |||||||||||||||||||
| Contingent consideration payment | — | — | (139,574) | — | |||||||||||||||||||
| Long-term non-cash compensation | 19,451 | 31,634 | 61,953 | 89,246 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,863 | 11,518 | 46,059 | 46,243 | |||||||||||||||||||
| Amortization of undeveloped leases | 2,710 | 2,649 | 10,925 | 13,300 | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (20,166) | 7,113 | 78,285 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (76,081) | — | (214,788) | |||||||||||||||||||
| Loss from discontinued operations | 723 | 162 | 1,467 | 2,078 | |||||||||||||||||||
| Loss (gain) from sale of assets | — | 972 | (12) | (17,899) | |||||||||||||||||||
| Other operating activities, net | 22,679 | 7,908 | (74,716) | (34,193) | |||||||||||||||||||
| Net (increase) decrease in non-cash working capital | 43,428 | (5,854) | (99,361) | (65,728) | |||||||||||||||||||
| Net cash provided by continuing operations activities | 543,021 | 501,518 | 1,748,755 | 2,180,244 | |||||||||||||||||||
| Investing Activities | |||||||||||||||||||||||
| Property additions and dry hole costs | (163,720) | (184,593) | (1,066,015) | (985,461) | |||||||||||||||||||
| Acquisition of oil and natural gas properties | (12,805) | (2,936) | (35,578) | (128,538) | |||||||||||||||||||
| Proceeds from sales of property, plant and equipment | — | 6,657 | 102,913 | 4,528 | |||||||||||||||||||
| Net cash required by investing activities | (176,525) | (180,872) | (998,680) | (1,109,471) | |||||||||||||||||||
| Financing Activities | |||||||||||||||||||||||
| Borrowings on revolving credit facility | 300,000 | 100,000 | 600,000 | 400,000 | |||||||||||||||||||
| Repayment of revolving credit facility | (300,000) | (100,000) | (600,000) | (400,000) | |||||||||||||||||||
| Retirement of debt | (249,500) | (201,674) | (498,175) | (647,707) | |||||||||||||||||||
| Early redemption of debt cost | — | (2,876) | — | (8,295) | |||||||||||||||||||
| Repurchase of common stock | (74,999) | — | (150,022) | — | |||||||||||||||||||
| Contingent consideration payment | — | — | (60,243) | (81,742) | |||||||||||||||||||
| Cash dividends paid | (42,321) | (38,865) | (170,978) | (128,219) | |||||||||||||||||||
| Distributions to noncontrolling interest | (9,330) | (37,765) | (29,382) | (183,038) | |||||||||||||||||||
| Withholding tax on stock-based incentive awards | (44) | (294) | (14,276) | (17,631) | |||||||||||||||||||
| Capital lease obligation payments | (165) | (161) | (622) | (636) | |||||||||||||||||||
| Issue costs of debt facility | — | (14,353) | (20) | (14,353) | |||||||||||||||||||
| Net cash required by financing activities | (376,359) | (295,988) | (923,718) | (1,081,621) | |||||||||||||||||||
| Net cash required by discontinued operations | — | — | — | (14,500) | |||||||||||||||||||
| Effect of exchange rate changes on cash and cash equivalents | (832) | 1,307 | (1,246) | (3,873) | |||||||||||||||||||
| Net (decrease) increase in cash and cash equivalents | (10,695) | 25,965 | (174,889) | (29,221) | |||||||||||||||||||
| Cash and cash equivalents at beginning of period | 327,769 | 465,998 | 491,963 | 521,184 | |||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 317,074 | 491,963 | $ | 317,074 | 491,963 | |||||||||||||||||
12
MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED NET INCOME (LOSS) (unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 116.3 | 199.4 | $ | 661.6 | 965.0 | |||||||||||||||||
| Discontinued operations loss | 0.7 | 0.2 | 1.5 | 2.1 | |||||||||||||||||||
| Net income from continuing operations attributable to Murphy | 117.0 | 199.6 | 663.1 | 967.1 | |||||||||||||||||||
Adjustments 2: | |||||||||||||||||||||||
| Write-off of previously suspended exploration well | — | 22.7 | 17.1 | 22.7 | |||||||||||||||||||
| Asset retirement obligation losses | 16.9 | 30.8 | 16.9 | 30.8 | |||||||||||||||||||
| Foreign exchange loss (gain) | 11.1 | 5.7 | 10.9 | (23.0) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (20.2) | 7.1 | 78.3 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (76.0) | — | (214.7) | |||||||||||||||||||
| Loss (gain) on sale of assets | — | 0.7 | — | (14.5) | |||||||||||||||||||
| Early redemption of debt cost | — | 3.5 | — | 10.3 | |||||||||||||||||||
| Total adjustments, before taxes | 28.0 | (32.8) | 52.0 | (110.1) | |||||||||||||||||||
Income tax expense (benefit) related to adjustments | (5.0) | 6.5 | (6.4) | 23.8 | |||||||||||||||||||
| Total adjustments after taxes | 23.0 | (26.3) | 45.6 | (86.3) | |||||||||||||||||||
| Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 140.0 | 173.3 | $ | 708.7 | 880.8 | |||||||||||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 0.90 | 1.10 | $ | 4.52 | 5.59 | |||||||||||||||||
1 Excludes results attributable to a noncontrolling interest in MP GOM.
2 Certain prior-period amounts have been reclassified to conform to the current period presentation.
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Adjusted net income from continuing operations attributable to Murphy. Adjusted net income excludes certain items that management believes affect the comparability of results between periods. Management believes this is important information to provide because it is used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income is a non-GAAP financial measure and should not be considered a substitute for Net income as determined in accordance with accounting principles generally accepted in the United States of America.
The pretax and income tax impacts for adjustments shown above are as follows by area of operations and exclude the share attributable to non-controlling interests.
| Three Months Ended December 31, 2023 | Year Ended December 31, 2023 | ||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Pretax | Tax | Net | Pretax | Tax | Net | |||||||||||||||||||||||||||||
Exploration & Production: | |||||||||||||||||||||||||||||||||||
| United States | $ | 10.8 | (2.2) | 8.6 | $ | 17.9 | (3.7) | 14.2 | |||||||||||||||||||||||||||
Other | 6.1 | — | 6.1 | 23.2 | — | 23.2 | |||||||||||||||||||||||||||||
| Corporate | 11.1 | (2.8) | 8.3 | 10.9 | (2.7) | 8.2 | |||||||||||||||||||||||||||||
Total adjustments | $ | 28.0 | (5.0) | 23.0 | $ | 52.0 | (6.4) | 45.6 | |||||||||||||||||||||||||||
13
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION (EBITDA)
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 116.3 | 199.4 | $ | 661.6 | 965.0 | |||||||||||||||||
| Income tax expense | 29.1 | 61.9 | 195.9 | 309.5 | |||||||||||||||||||
| Interest expense, net | 23.7 | 34.7 | 112.4 | 150.8 | |||||||||||||||||||
Depreciation, depletion and amortization expense 2 | 206.0 | 195.7 | 836.7 | 748.2 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 375.1 | 491.7 | $ | 1,806.6 | 2,173.5 | |||||||||||||||||
Accretion of asset retirement obligations 2 | 10.6 | 10.2 | 41.0 | 40.9 | |||||||||||||||||||
| Write-off of previously suspended exploration well | — | 22.7 | 17.1 | 22.7 | |||||||||||||||||||
| Asset retirement obligation losses | 16.9 | 30.8 | 16.9 | 30.8 | |||||||||||||||||||
| Foreign exchange loss (gain) | 11.1 | 5.7 | 10.8 | (23.0) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (20.2) | 7.1 | 78.3 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (76.0) | — | (214.7) | |||||||||||||||||||
| Discontinued operations loss | 0.7 | 0.2 | 1.5 | 2.1 | |||||||||||||||||||
Loss (gain) on sale of assets 2 | — | 0.7 | — | (14.5) | |||||||||||||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 414.4 | 465.8 | $ | 1,901.0 | 2,096.1 | |||||||||||||||||
1 Excludes results attributable to a noncontrolling interest in MP GOM.
2 Depreciation, depletion, and amortization expense, loss (gain) on sale of assets, and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI).
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management believes EBITDA and adjusted EBITDA are important information to provide because they are used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.
14
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION AND EXPLORATION (EBITDAX)
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 116.3 | 199.4 | $ | 661.6 | 965.0 | |||||||||||||||||
| Income tax expense | 29.1 | 61.9 | 195.9 | 309.5 | |||||||||||||||||||
| Interest expense, net | 23.7 | 34.7 | 112.4 | 150.8 | |||||||||||||||||||
Depreciation, depletion and amortization expense 2 | 206.0 | 195.7 | 836.7 | 748.2 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | 375.1 | 491.7 | 1,806.6 | 2,173.5 | |||||||||||||||||||
Exploration expenses 2 | 82.0 | 61.0 | 204.6 | 133.2 | |||||||||||||||||||
| EBITDAX attributable to Murphy (Non-GAAP) | 457.1 | 552.7 | 2,011.2 | 2,306.7 | |||||||||||||||||||
Accretion of asset retirement obligations 2 | 10.6 | 10.2 | 41.0 | 40.9 | |||||||||||||||||||
| Asset retirement obligation losses | 16.9 | 30.8 | 16.9 | 30.8 | |||||||||||||||||||
| Foreign exchange loss (gain) | 11.1 | 5.7 | 10.8 | (23.0) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (20.2) | 7.1 | 78.3 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (76.0) | — | (214.7) | |||||||||||||||||||
| Discontinued operations loss | 0.7 | 0.2 | 1.5 | 2.1 | |||||||||||||||||||
Loss (gain) on sale of assets 2 | — | 0.7 | — | (14.5) | |||||||||||||||||||
| Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 496.4 | $ | 504.1 | $ | 2,088.5 | $ | 2,206.6 | |||||||||||||||
1 Excludes results attributable to a noncontrolling interest in MP GOM.
2 Depreciation, depletion, and amortization expense, accretion of asset retirement obligations, loss (gain) on sale of assets, and exploration expenses used in the computation of adjusted EBITDAX exclude the portion attributable to the non-controlling interest (NCI).
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX. Management believes EBITDAX and adjusted EBITDAX are important information to provide because they are used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for Net income or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.
15
MURPHY OIL CORPORATION
FUNCTIONAL RESULTS OF OPERATIONS (unaudited)
| Three Months Ended December 31, 2023 | Three Months Ended December 31, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
United States 1 | $ | 726.1 | 199.8 | $ | 802.0 | 296.0 | ||||||||
| Canada | 114.1 | 6.8 | 180.6 | 22.9 | ||||||||||
| Other | 3.9 | (15.5) | 4.3 | (23.5) | ||||||||||
| Total exploration and production | 844.1 | 191.1 | 986.9 | 295.4 | ||||||||||
| Corporate | 0.1 | (50.7) | (11.7) | (74.6) | ||||||||||
| Continuing operations | 844.2 | 140.4 | 975.2 | 220.8 | ||||||||||
| Discontinued operations, net of tax | — | (0.7) | — | (0.2) | ||||||||||
| Total including noncontrolling interest | $ | 844.2 | 139.7 | $ | 975.2 | 220.6 | ||||||||
| Net income attributable to Murphy | 116.3 | 199.4 | ||||||||||||
| Year Ended December 31, 2023 | Year Ended December 31, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
United States 1 | $ | 2,928.3 | 905.1 | $ | 3,461.2 | 1,521.9 | ||||||||
| Canada | 517.5 | 41.6 | 762.9 | 134.2 | ||||||||||
| Other | 11.0 | (65.5) | 23.0 | (77.0) | ||||||||||
| Total exploration and production | 3,456.8 | 881.2 | 4,247.1 | 1,579.1 | ||||||||||
| Corporate | 3.4 | (156.0) | (314.4) | (438.3) | ||||||||||
| Continuing operations | 3,460.2 | 725.2 | 3,932.7 | 1,140.8 | ||||||||||
| Discontinued operations, net of tax | — | (1.5) | — | (2.1) | ||||||||||
| Total including noncontrolling interest | $ | 3,460.2 | 723.7 | $ | 3,932.7 | 1,138.7 | ||||||||
| Net income attributable to Murphy | 661.6 | 965.0 | ||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
16
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
THREE MONTHS ENDED DECEMBER 31, 2023, AND 2022
| (Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Three Months Ended December 31, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 726.1 | 106.6 | 3.9 | 836.6 | |||||||||
| Sales of purchased natural gas | — | 7.6 | — | 7.6 | ||||||||||
| Lease operating expenses | 158.3 | 38.0 | 0.5 | 196.8 | ||||||||||
| Severance and ad valorem taxes | 7.3 | 0.3 | — | 7.6 | ||||||||||
| Transportation, gathering and processing | 37.9 | 19.9 | — | 57.8 | ||||||||||
| Costs of purchased natural gas | — | 4.3 | — | 4.3 | ||||||||||
| Depreciation, depletion and amortization | 174.2 | 35.2 | 0.7 | 210.1 | ||||||||||
| Accretion of asset retirement obligations | 9.8 | 1.9 | 0.1 | 11.8 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 62.2 | — | (0.2) | 62.0 | ||||||||||
| Geological and geophysical | 4.0 | — | 6.5 | 10.5 | ||||||||||
| Other exploration | 1.1 | 0.1 | 5.8 | 7.0 | ||||||||||
| 67.3 | 0.1 | 12.1 | 79.5 | |||||||||||
| Undeveloped lease amortization | 1.9 | — | 0.8 | 2.7 | ||||||||||
| Total exploration expenses | 69.2 | 0.1 | 12.9 | 82.2 | ||||||||||
| Selling and general expenses | 4.0 | 5.2 | 3.6 | 12.8 | ||||||||||
| Other | 17.1 | 3.6 | 7.3 | 28.0 | ||||||||||
| Results of operations before taxes | 248.3 | 5.7 | (21.2) | 232.8 | ||||||||||
| Income tax provisions | 48.5 | (1.1) | (5.7) | 41.7 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 199.8 | 6.8 | (15.5) | 191.1 | |||||||||
| Three Months Ended December 31, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 802.0 | 131.2 | 4.3 | 937.5 | |||||||||
| Sales of purchased natural gas | — | 49.4 | — | 49.4 | ||||||||||
| Lease operating expenses | 154.5 | 41.7 | 0.3 | 196.5 | ||||||||||
| Severance and ad valorem taxes | 9.3 | 0.3 | — | 9.6 | ||||||||||
| Transportation, gathering and processing | 42.2 | 18.3 | — | 60.5 | ||||||||||
| Costs of purchased natural gas | — | 46.7 | — | 46.7 | ||||||||||
| Depreciation, depletion and amortization | 167.4 | 30.8 | 1.0 | 199.2 | ||||||||||
| Accretion of asset retirement obligations | 9.2 | 2.3 | — | 11.5 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 23.5 | — | 23.4 | 46.9 | ||||||||||
| Geological and geophysical | 4.6 | 0.1 | 0.4 | 5.1 | ||||||||||
| Other exploration | 1.6 | 0.1 | 4.6 | 6.3 | ||||||||||
| 29.7 | 0.2 | 28.4 | 58.3 | |||||||||||
| Undeveloped lease amortization | 2.0 | — | 0.6 | 2.6 | ||||||||||
| Total exploration expenses | 31.7 | 0.2 | 29.0 | 60.9 | ||||||||||
| Selling and general expenses | 6.3 | 7.8 | (4.3) | 9.8 | ||||||||||
| Other | 15.9 | 5.9 | 2.1 | 23.9 | ||||||||||
| Results of operations before taxes | 365.5 | 26.6 | (23.8) | 368.3 | ||||||||||
| Income tax provisions | 69.5 | 3.7 | (0.3) | 72.9 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 296.0 | 22.9 | (23.5) | 295.4 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
17
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
YEAR ENDED DECEMBER 31, 2023, AND 2022
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Year Ended December 31, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 2,928.3 | 445.3 | 11.0 | 3,384.6 | |||||||||
| Sales of purchased natural gas | — | 72.2 | — | 72.2 | ||||||||||
| Lease operating expenses | 630.7 | 151.8 | 1.9 | 784.4 | ||||||||||
| Severance and ad valorem taxes | 41.4 | 1.4 | — | 42.8 | ||||||||||
| Transportation, gathering and processing | 157.0 | 76.0 | — | 233.0 | ||||||||||
| Costs of purchased natural gas | — | 51.7 | — | 51.7 | ||||||||||
| Depreciation, depletion and amortization | 706.0 | 142.2 | 2.3 | 850.5 | ||||||||||
| Accretion of asset retirement obligations | 37.8 | 7.8 | 0.4 | 46.0 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 153.1 | — | 16.7 | 169.8 | ||||||||||
| Geological and geophysical | 6.6 | 0.1 | 19.4 | 26.1 | ||||||||||
| Other exploration | 6.8 | 0.3 | 20.9 | 28.0 | ||||||||||
| 166.5 | 0.4 | 57.0 | 223.9 | |||||||||||
| Undeveloped lease amortization | 8.1 | 0.1 | 2.7 | 10.9 | ||||||||||
| Total exploration expenses | 174.6 | 0.5 | 59.7 | 234.8 | ||||||||||
| Selling and general expenses | 11.8 | 16.5 | 9.4 | 37.7 | ||||||||||
| Other | 31.2 | 16.8 | 8.9 | 56.9 | ||||||||||
| Results of operations before taxes | 1,137.8 | 52.8 | (71.6) | 1,119.0 | ||||||||||
Income tax provisions (benefits) | 232.7 | 11.2 | (6.1) | 237.8 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 905.1 | 41.6 | (65.5) | 881.2 | |||||||||
| Year Ended December 31, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 3,461.0 | 581.4 | 22.8 | 4,065.2 | |||||||||
| Sales of purchased natural gas | 0.2 | 181.5 | — | 181.7 | ||||||||||
| Lease operating expenses | 522.7 | 155.1 | 1.5 | 679.3 | ||||||||||
| Severance and ad valorem taxes | 55.7 | 1.3 | — | 57.0 | ||||||||||
| Transportation, gathering and processing | 142.2 | 70.5 | — | 212.7 | ||||||||||
| Costs of purchased natural gas | 0.2 | 171.8 | — | 172.0 | ||||||||||
| Depreciation, depletion and amortization | 617.0 | 141.5 | 5.4 | 763.9 | ||||||||||
| Accretion of asset retirement obligations | 36.5 | 9.6 | 0.1 | 46.2 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 23.0 | — | 59.1 | 82.1 | ||||||||||
| Geological and geophysical | 8.3 | 0.3 | 1.8 | 10.4 | ||||||||||
| Other exploration | 7.5 | 0.5 | 19.3 | 27.3 | ||||||||||
| 38.8 | 0.8 | 80.2 | 119.8 | |||||||||||
| Undeveloped lease amortization | 8.7 | 0.2 | 4.4 | 13.3 | ||||||||||
| Total exploration expenses | 47.5 | 1.0 | 84.6 | 133.1 | ||||||||||
| Selling and general expenses | 20.4 | 21.9 | 2.2 | 44.5 | ||||||||||
| Other | 126.3 | 12.4 | 3.1 | 141.8 | ||||||||||
| Results of operations before taxes | 1,892.7 | 177.8 | (74.1) | 1,996.4 | ||||||||||
Income tax provisions | 370.8 | 43.6 | 2.9 | 417.3 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 1,521.9 | 134.2 | (77.0) | 1,579.1 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
18
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
(Dollars per barrel of oil equivalents sold) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
United States – Onshore | |||||||||||||||||||||||
Lease operating expense | $ | 12.73 | 11.26 | $ | 12.48 | 10.94 | |||||||||||||||||
Severance and ad valorem taxes | 2.39 | 2.96 | 3.26 | 4.26 | |||||||||||||||||||
Depreciation, depletion and amortization (DD&A) expense | 26.24 | 25.50 | 26.29 | 25.55 | |||||||||||||||||||
United States – Offshore1 | |||||||||||||||||||||||
| Lease operating expense | $ | 15.06 | 14.63 | $ | 14.46 | 13.19 | |||||||||||||||||
| Severance and ad valorem taxes | 0.05 | 0.07 | 0.06 | 0.07 | |||||||||||||||||||
DD&A expense | 12.18 | 11.07 | 11.72 | 10.12 | |||||||||||||||||||
Canada – Onshore | |||||||||||||||||||||||
Lease operating expense | $ | 5.67 | 7.69 | $ | 5.89 | 6.75 | |||||||||||||||||
Severance and ad valorem taxes | 0.05 | 0.06 | 0.06 | 0.06 | |||||||||||||||||||
DD&A expense | 5.31 | 5.67 | 5.60 | 6.20 | |||||||||||||||||||
Canada – Offshore | |||||||||||||||||||||||
| Lease operating expense | $ | 11.66 | 14.21 | $ | 12.30 | 14.20 | |||||||||||||||||
DD&A expense | 8.94 | 10.55 | 9.47 | 12.25 | |||||||||||||||||||
| Total E&P continuing operations | |||||||||||||||||||||||
| Lease operating expense | $ | 11.24 | 11.90 | $ | 11.18 | 10.65 | |||||||||||||||||
Severance and ad valorem taxes | 0.44 | 0.59 | 0.61 | 0.89 | |||||||||||||||||||
DD&A expense2 | 12.00 | 12.06 | 12.12 | 11.98 | |||||||||||||||||||
| Total oil and gas continuing operations – excluding noncontrolling interest | |||||||||||||||||||||||
Lease operating expense | $ | 11.00 | 11.74 | $ | 10.99 | 10.50 | |||||||||||||||||
Severance and ad valorem taxes | 0.45 | 0.61 | 0.63 | 0.93 | |||||||||||||||||||
DD&A expense2 | 12.05 | 12.13 | 12.20 | 12.09 | |||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 Excludes expenses attributable to the Corporate segment.
19
MURPHY OIL CORPORATION
CAPITAL EXPENDITURES
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
(Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
United States1 | $ | 193.7 | 199.8 | $ | 837.7 | 877.4 | |||||||||||||||||
| Canada | 35.5 | 33.4 | 206.1 | 209.3 | |||||||||||||||||||
| Other | 14.5 | 24.3 | 70.2 | 74.8 | |||||||||||||||||||
| Total | 243.7 | 257.5 | 1,114.0 | 1,161.5 | |||||||||||||||||||
| Corporate | 8.7 | 7.8 | 24.1 | 21.7 | |||||||||||||||||||
Total capital expenditures - continuing operations2 | 252.4 | 265.3 | 1,138.1 | 1,183.2 | |||||||||||||||||||
Charged to exploration expenses3 | |||||||||||||||||||||||
United States1 | 67.3 | 29.8 | 166.5 | 38.8 | |||||||||||||||||||
| Canada | 0.1 | 0.1 | 0.4 | 0.8 | |||||||||||||||||||
| Other | 12.1 | 28.4 | 57.0 | 80.2 | |||||||||||||||||||
| Total charged to exploration expenses - continuing operations | 79.5 | 58.3 | 223.9 | 119.8 | |||||||||||||||||||
| Total capitalized | $ | 172.9 | 207.0 | $ | 914.2 | 1,063.4 | |||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the three months ended December 31, 2023, total capital expenditures excluding acquisition-related costs of $20.5 million (Côte d’Ivoire and Gulf of Mexico) (2022: $16.1 million) and noncontrolling interest (NCI) of $12.9 million (2022: $9.3 million) is $219.0 million (2022: $239.9 million). For the twelve months ended December 31, 2023, total capital expenditures excluding acquisition-related costs of $59.9 million (Côte d’Ivoire, Vietnam and Gulf of Mexico) (2022: $141.7 million) and noncontrolling interest (NCI) of $70.2 million (2022: $25.9 million) is $1,008.0 million (2022: $1,015.6 million).
3 For the three months and year ended December 31, 2023, charges to exploration expense excludes amortization of undeveloped leases of $2.7 million (2022: $2.6 million) and $10.9 million (2022 $13.3 million), respectively. For the three months ended December 31, 2023, charges to exploration expense excluding NCI of $0.3 million (2022: $0) is $79.2 million. For the twelve months ended December 31, 2023, charges to exploration expense excluding previously suspended exploration costs of $17.1 million (2022: $22.7 million) and NCI of $30.2 million (2022: $0) is $176.6 million (2022: $97.1 million).
20
MURPHY OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited)
| (Thousands of dollars) | December 31, 2023 | December 31, 2022 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 317,074 | 491,963 | ||||||||
Accounts receivable, net | 343,992 | 391,152 | |||||||||
| Inventories | 54,454 | 54,513 | |||||||||
| Prepaid expenses | 36,674 | 34,697 | |||||||||
| Total current assets | 752,194 | 972,325 | |||||||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization | 8,225,197 | 8,228,016 | |||||||||
| Operating lease assets | 745,185 | 946,406 | |||||||||
| Deferred income taxes | 435 | 117,889 | |||||||||
| Deferred charges and other assets | 43,686 | 44,316 | |||||||||
| Total assets | $ | 9,766,697 | 10,308,952 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current maturities of long-term debt, finance lease | $ | 723 | 687 | ||||||||
| Accounts payable | 446,891 | 543,786 | |||||||||
| Income taxes payable | 21,007 | 26,544 | |||||||||
| Other taxes payable | 29,339 | 22,819 | |||||||||
| Operating lease liabilities | 207,840 | 220,413 | |||||||||
| Other accrued liabilities | 140,745 | 443,585 | |||||||||
| Total current liabilities | 846,545 | 1,257,834 | |||||||||
| Long-term debt, including finance lease obligation | 1,328,352 | 1,822,452 | |||||||||
| Asset retirement obligations | 904,051 | 817,268 | |||||||||
| Deferred credits and other liabilities | 309,605 | 304,948 | |||||||||
| Non-current operating lease liabilities | 551,845 | 742,654 | |||||||||
| Deferred income taxes | 276,646 | 214,903 | |||||||||
| Total liabilities | 4,217,044 | 5,160,059 | |||||||||
| Equity | |||||||||||
| Common Stock, par $1.00 | 195,101 | 195,101 | |||||||||
| Capital in excess of par value | 880,297 | 893,578 | |||||||||
| Retained earnings | 6,546,079 | 6,055,498 | |||||||||
| Accumulated other comprehensive loss | (521,117) | (534,686) | |||||||||
| Treasury stock | (1,737,566) | (1,614,717) | |||||||||
| Murphy Shareholders' Equity | 5,362,794 | 4,994,774 | |||||||||
| Noncontrolling interest | 186,859 | 154,119 | |||||||||
| Total equity | 5,549,653 | 5,148,893 | |||||||||
| Total liabilities and equity | $ | 9,766,697 | 10,308,952 | ||||||||
21
MURPHY OIL CORPORATION
PRODUCTION SUMMARY
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
United States - Onshore | 22,277 | 22,521 | 24,070 | 24,437 | ||||||||||||||||||||||
United States - Offshore 1 | 71,360 | 74,406 | 73,473 | 65,411 | ||||||||||||||||||||||
Canada - Onshore | 2,443 | 3,344 | 2,937 | 4,005 | ||||||||||||||||||||||
Canada - Offshore | 3,741 | 2,643 | 3,020 | 2,812 | ||||||||||||||||||||||
| Other | 258 | 654 | 250 | 700 | ||||||||||||||||||||||
Total net crude oil and condensate | 100,079 | 103,568 | 103,750 | 97,365 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
United States - Onshore | 4,699 | 4,924 | 4,617 | 5,181 | ||||||||||||||||||||||
United States - Offshore 1 | 5,195 | 5,150 | 5,924 | 4,597 | ||||||||||||||||||||||
Canada - Onshore | 610 | 785 | 681 | 903 | ||||||||||||||||||||||
Total net natural gas liquids | 10,504 | 10,859 | 11,222 | 10,681 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
United States - Onshore | 26,730 | 29,104 | 25,863 | 29,050 | ||||||||||||||||||||||
United States - Offshore 1 | 65,714 | 68,282 | 70,239 | 63,380 | ||||||||||||||||||||||
Canada - Onshore | 393,805 | 300,756 | 369,906 | 310,230 | ||||||||||||||||||||||
Total net natural gas | 486,249 | 398,142 | 466,008 | 402,660 | ||||||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 191,625 | 180,784 | 192,640 | 175,156 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (6,296) | (6,614) | (6,210) | (7,452) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (255) | (249) | (220) | (280) | ||||||||||||||||||||||
Net natural gas – thousands of cubic feet per day | (2,368) | (1,992) | (2,089) | (2,468) | ||||||||||||||||||||||
Total noncontrolling interest 2,3 | (6,946) | (7,195) | (6,778) | (8,143) | ||||||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 184,679 | 173,589 | 185,862 | 167,013 | ||||||||||||||||||||||
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
22
MURPHY OIL CORPORATION
WEIGHTED AVERAGE PRICE SUMMARY
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | |||||||||||||||||||||||
United States - Onshore | $ | 78.81 | 83.06 | $ | 76.96 | 96.00 | |||||||||||||||||
United States - Gulf of Mexico 1 | 79.38 | 82.11 | 77.38 | 94.21 | |||||||||||||||||||
Canada - Onshore 2 | 72.16 | 80.75 | 72.84 | 89.88 | |||||||||||||||||||
Canada - Offshore 2 | 84.49 | 87.47 | 84.20 | 107.47 | |||||||||||||||||||
Other 2 | 94.24 | 101.20 | 86.60 | 94.37 | |||||||||||||||||||
| Natural gas liquids – dollars per barrel | |||||||||||||||||||||||
| United States - Onshore | 19.47 | 24.20 | 19.69 | 33.85 | |||||||||||||||||||
United States - Gulf of Mexico 1 | 21.67 | 25.90 | 21.94 | 36.01 | |||||||||||||||||||
Canada - Onshore 2 | 24.87 | 48.99 | 35.87 | 55.65 | |||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | |||||||||||||||||||||||
| United States - Onshore | 2.33 | 4.70 | 2.26 | 6.04 | |||||||||||||||||||
United States - Gulf of Mexico 1 | 2.65 | 6.25 | 2.78 | 6.97 | |||||||||||||||||||
Canada - Onshore 2 | 2.02 | 2.96 | 2.06 | 2.76 | |||||||||||||||||||
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
23
MURPHY OIL CORPORATION
FIXED PRICE FORWARD SALES AND COMMODITY HEDGE POSITIONS (unaudited)
AS OF JANUARY 23, 2024
| Volumes (MMcf/d) | Price/MCF | Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type 1 | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 162 | C$2.39 | 1/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 25 | US$1.98 | 1/1/2024 | 10/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 15 | US$1.98 | 11/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
1 Fixed price forward sale contracts are accounted for as normal sales and purchases for accounting purposes.
24
MURPHY OIL CORPORATION
FIRST QUARTER 2024 GUIDANCE
| Oil BOPD | NGLs BOPD | Gas MCFD | Total BOEPD | ||||||||||||||||||||
| Production – net | |||||||||||||||||||||||
| U.S. – Eagle Ford Shale | 19,400 | 4,400 | 24,400 | 27,900 | |||||||||||||||||||
| – Gulf of Mexico excluding NCI | 59,500 | 4,700 | 56,500 | 73,600 | |||||||||||||||||||
| Canada – Tupper Montney | — | — | 327,100 | 54,500 | |||||||||||||||||||
| – Kaybob Duvernay and Placid Montney | 2,000 | 400 | 7,000 | 3,600 | |||||||||||||||||||
| – Offshore | 7,200 | — | — | 7,200 | |||||||||||||||||||
| Other | 200 | — | — | 200 | |||||||||||||||||||
Total net production (BOEPD) - excluding NCI 1 | 163,000 to 171,000 | ||||||||||||||||||||||
| Exploration expense ($ millions) | $24 | ||||||||||||||||||||||
| FULL YEAR 2024 GUIDANCE | |||||||||||||||||||||||
Total net production (BOEPD) - excluding NCI 2 | 180,000 to 188,000 | ||||||||||||||||||||||
Capital expenditures – excluding NCI ($ millions) 3 | $920 to $1,020 | ||||||||||||||||||||||
| ¹ Excludes noncontrolling interest of MP GOM of 6,300 BOPD of oil, 300 BOPD of NGLs, and 2,500 MCFD gas. | |||||||||||||||||||||||
| ² Excludes noncontrolling interest of MP GOM of 6,400 BOPD of oil, 300 BOPD of NGLs, and 2,500 MCFD gas. | |||||||||||||||||||||||
| ³ Excludes noncontrolling interest of MP GOM of $22 million. | |||||||||||||||||||||||
25
