UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): November 2, 2023
(Exact name of registrant as specified in its charter)
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
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Securities registered pursuant to Section 12(b) of the Act:
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Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). Emerging growth company ☐
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. ☐
Item 2.02. Results of Operations and Financial Condition
The following information is furnished pursuant to Item 2.02, “Results of Operations and Financial Condition.”
On November 2, 2023 Murphy Oil Corporation issued a news release announcing its financial and operating results for the quarter ended September 30, 2023. The full text of this news release is attached hereto as Exhibit 99.1.
Item 9.01. Financial Statements and Exhibits
| (d) | Exhibits | ||||
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
MURPHY OIL CORPORATION | ||||||||
| Date: November 2, 2023 | ||||||||
By: | /s/ Paul D. Vaughan | |||||||
| Paul D. Vaughan | ||||||||
Vice President and Controller | ||||||||
Exhibit Index
| Exhibit No. | |||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document) | ||||
EXHIBIT 99.1
MURPHY OIL CORPORATION ANNOUNCES THIRD QUARTER 2023 FINANCIAL AND OPERATING RESULTS, ADVANCES CAPITAL ALLOCATION FRAMEWORK, INCREASES SHARE REPURCHASE AUTHORIZATION, RAISES FULL YEAR 2023 PRODUCTION GUIDANCE
Exceeded Upper End of Guidance Range With Production of 202 MBOEPD,
Sanctioned Lac Da Vang Field Development Project in Vietnam,
Executed $249 Million of Debt Reduction, Repurchased $75 Million of Shares Outstanding
HOUSTON, Texas, November 2, 2023 – Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the third quarter ended September 30, 2023, including net income attributable to Murphy of $255 million, or $1.63 net income per diluted share. Excluding discontinued operations and other items affecting comparability between periods, adjusted net income attributable to Murphy was $249 million, or $1.59 adjusted net income per diluted share.
Unless otherwise noted, the financial and operating highlights and metrics discussed in this news release exclude noncontrolling interest (NCI). 1
Highlights for the third quarter include:
•Exceeded upper end of guidance range with production of 202 thousand barrels of oil equivalent per day (MBOEPD), including 103 thousand barrels of oil per day (MBOPD)
•Redeemed remaining $249 million of 5.75% Senior Notes due 2025
•Repurchased $75 million, or 1.7 million shares outstanding, at an average price of $44.53 per share
•Closed divestiture of certain non-core operated Kaybob Duvernay and all non-operated Placid Montney assets for net cash proceeds of $103 million
Subsequent to the third quarter:
•Sanctioned by board the Lac Da Vang field development project in Vietnam, targeting first oil in 2026
•Increased share repurchase authorization by $300 million
“Murphy had another great quarter with strong execution across our assets, resulting in significant free cash flow that we dedicated to paying down debt and repurchasing stock in accordance with our capital allocation framework. We also utilized part of the proceeds from the divestiture of a non-core portion of our Canadian assets to support our new country entry in Côte d’Ivoire and advance our Lac Da Vang field development project in Vietnam,” said Roger W. Jenkins, President and Chief Executive Officer. “I am delighted we are progressing our strategy
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of Delever, Execute, Explore, Return as we close out 2023, and I look forward to Murphy’s many opportunities in the new year.”
THIRD QUARTER 2023 RESULTS
The company recorded net income attributable to Murphy of $255 million, or $1.63 net income per diluted share, for the third 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 $249 million, or $1.59 adjusted net income per diluted share for the same period. The only adjustment to net income this quarter was foreign exchange gain totaling $9 million before tax. Details for third 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 $595 million. Earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) attributable to Murphy were $618 million. Adjusted EBITDA attributable to Murphy was $597 million. Adjusted EBITDAX attributable to Murphy was $620 million. Reconciliations for third quarter EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX can be found in the attached schedules.
Third quarter production averaged 202 MBOEPD and consisted of 51 percent oil volumes, or 103 MBOPD. Production for the quarter exceeded the upper end of the guidance range due to several factors, including strong well performance across onshore assets, lower realized royalty rates in the Tupper Montney natural gas asset and outperformance in the Gulf of Mexico due to an absence of hurricane downtime. Details for third quarter production can be found in the attached schedules.
FINANCIAL POSITION
Murphy had approximately $1.1 billion of liquidity on September 30, 2023, with no borrowings on the $800 million credit facility and $328 million of cash and cash equivalents, inclusive of NCI.
On September 15, 2023, the company announced the redemption of its remaining $249 million of 5.75 percent Senior Notes due 2025. Murphy funded the redemption during the third quarter and the obligation was satisfied. As a result, at the end of the third quarter, Murphy’s total debt was reduced to $1.6 billion, and consisted of long-term, fixed-rate notes with a weighted average maturity of 7.8 years and a weighted average coupon of 6.2 percent. Overall, Murphy has achieved a 47 percent, or $1.4 billion, reduction in total debt since year-end 2020.
SHARE REPURCHASE PROGRAM
During the third quarter, Murphy repurchased $75 million, or 1.7 million shares outstanding, at an average price of $44.53 per share. Subsequent to the quarter, the share repurchase authorization was increased by $300 million, and Murphy now has $525 million remaining.
“I am pleased that the adjusted free cash flow generated allowed us to execute the senior notes redemption and share repurchases under Murphy 2.0 of our capital allocation framework. With
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continued operational success next year, we will further strengthen our balance sheet and enhance shareholder returns through the allocations established in our framework,” said Jenkins.
OPERATIONS SUMMARY
Onshore
In the third quarter of 2023, the onshore business produced approximately 113 MBOEPD, which included 33 percent liquids volumes.
Eagle Ford Shale – Production averaged 38 MBOEPD with 74 percent oil volumes and 88 percent liquids volumes. As planned, Murphy brought online four operated wells in Catarina and three operated wells in Tilden during the quarter.
Tupper Montney – Natural gas production averaged 414 million cubic feet per day (MMCFD) in the third quarter. Production exceeded guidance by 35 MMCFD, of which 17 MMCFD was due to record high initial production rates, and 18 MMCFD was the result of a lower realized royalty rate of 3.9 percent.
Kaybob Duvernay – During the third quarter, production averaged 5 MBOEPD with 67 percent liquids volumes. As previously announced, in the third quarter Murphy closed the divestment of certain non-core operated Kaybob Duvernay and all of its non-operated Placid Montney assets for cash proceeds of $103 million, with an effective date of March 1, 2023. As a result of this transaction, Murphy no longer holds working interests in Placid Montney.
Offshore
Excluding NCI, the offshore business produced approximately 89 MBOEPD for the third quarter, which included 81 percent oil.
Gulf of Mexico – Production averaged approximately 86 MBOEPD, consisting of 80 percent oil during the third quarter. While production was positively impacted by the absence of Gulf of Mexico storms in the quarter, a mechanical issue developed at a well in the operated Neidermeyer field, causing production from that well to be shut in late in the quarter. In addition, a well in the operated Dalmatian field remains offline due to a mechanical issue that occurred earlier in the year. Workovers are planned for both wells in 2024.
Canada – In the third quarter, production averaged 3 MBOEPD, consisting of 100 percent oil, all from the Hibernia field. The asset life extension project is progressing for the non-operated Terra Nova floating, production, storage and offloading vessel, which Murphy anticipates will return to production by year-end 2023.
Vietnam – Subsequent to the third quarter, the Board of Directors sanctioned the Lac Da Vang field development project in Block 15-1/05 of the Cuu Long Basin. Murphy as operator holds a 40 percent working interest in the block. This project is expected to achieve first oil in 2026, with development phased through 2029. Overall, the field has an estimated ultimate recovery of 100 million barrels of oil equivalent (MMBOE) gross resources, with peak gross production of 30 to 40 MBOEPD.
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Côte d’Ivoire – During the quarter, Murphy commenced initial work, including a review of commerciality and field development concepts for the Paon discovery in Block CI-103.
EXPLORATION
Gulf of Mexico – The company advanced preparations to resume drilling the Oso #1 (Atwater Valley 138) exploration well.
Côte d’Ivoire – Murphy commenced seismic reprocessing during the third quarter.
2023 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Third quarter accrued CAPEX of $162 million was lower than guidance primarily due to timing of non-operated projects. Murphy maintains its 2023 accrued CAPEX range of $950 million to $1.025 billion, which excludes $49 million in acquisition-related CAPEX for Côte d’Ivoire and Vietnam.
The company is raising its full year 2023 production range to 185 to 187 MBOEPD, consisting of approximately 53 percent oil and 59 percent liquids volumes. This represents a 3 MBOEPD increase in the midpoint from the previous range.
Production for fourth quarter 2023 is estimated to be in the range of 181.5 to 189.5 MBOEPD with 95 MBOPD, or 51 percent, oil volumes. This range includes planned downtime of 500 BOEPD in the Gulf of Mexico and 1.5 MBOEPD onshore. Production is also impacted by mechanical issues in two operated Gulf of Mexico wells, with plans in place for workovers in 2024.
Both production and CAPEX guidance ranges exclude NCI. Detailed guidance for the fourth quarter and full year 2023 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.
CONFERENCE CALL AND WEBCAST SCHEDULED FOR NOVEMBER 2, 2023
Murphy will host a conference call to discuss third quarter 2023 financial and operating results on Thursday, November 2, 2023, at 9:00 a.m. EDT. 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 10064350.
FINANCIAL DATA
Summary financial data and operating statistics for third quarter 2023, with comparisons to the same period from the previous year, are contained in the following schedules. Additionally, a schedule indicating the impacts of items affecting comparability of results between periods, a
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reconciliation of EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX between periods, as well as guidance for the fourth quarter and full year 2023, 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 beyond. Additional information can be found on the company’s website at www.murphyoilcorp.com.
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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; 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. 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 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.
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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.
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 September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | 945,889 | 1,120,909 | $ | 2,541,956 | 3,101,736 | |||||||||||||||||
| Sales of purchased natural gas | 7,877 | 45,500 | 64,628 | 132,285 | |||||||||||||||||||
| Total revenue from sales to customers | 953,766 | 1,166,409 | 2,606,584 | 3,234,021 | |||||||||||||||||||
| Gain (loss) on derivative instruments | — | 115,191 | — | (308,654) | |||||||||||||||||||
| Gain on sale of assets and other income | 5,879 | 21,825 | 9,365 | 32,076 | |||||||||||||||||||
| Total revenues and other income | 959,645 | 1,303,425 | 2,615,949 | 2,957,443 | |||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 193,402 | 198,710 | 587,678 | 482,887 | |||||||||||||||||||
| Severance and ad valorem taxes | 10,937 | 15,140 | 35,142 | 47,340 | |||||||||||||||||||
| Transportation, gathering and processing | 61,518 | 55,348 | 175,308 | 152,219 | |||||||||||||||||||
| Costs of purchased natural gas | 5,467 | 43,622 | 47,393 | 125,258 | |||||||||||||||||||
| Exploration expenses, including undeveloped lease amortization | 26,514 | 9,491 | 152,489 | 72,208 | |||||||||||||||||||
| Selling and general expenses | 30,745 | 29,348 | 74,398 | 90,007 | |||||||||||||||||||
| Depreciation, depletion and amortization | 237,493 | 214,521 | 648,830 | 574,501 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,675 | 11,286 | 34,196 | 34,725 | |||||||||||||||||||
| Other operating expense (benefit) | 4,385 | (27,129) | 21,333 | 115,726 | |||||||||||||||||||
| Total costs and expenses | 582,136 | 550,337 | 1,776,767 | 1,694,871 | |||||||||||||||||||
| Operating income from continuing operations | 377,509 | 753,088 | 839,182 | 1,262,572 | |||||||||||||||||||
| Other loss | |||||||||||||||||||||||
| Other income | 8,811 | 18,301 | 1,044 | 21,114 | |||||||||||||||||||
| Interest expense, net | (29,984) | (37,440) | (88,695) | (116,102) | |||||||||||||||||||
| Total other loss | (21,173) | (19,139) | (87,651) | (94,988) | |||||||||||||||||||
| Income from continuing operations before income taxes | 356,336 | 733,949 | 751,531 | 1,167,584 | |||||||||||||||||||
| Income tax expense | 78,111 | 159,451 | 166,813 | 247,574 | |||||||||||||||||||
| Income from continuing operations | 278,225 | 574,498 | 584,718 | 920,010 | |||||||||||||||||||
| Loss from discontinued operations, net of income taxes | (421) | (422) | (744) | (1,916) | |||||||||||||||||||
| Net income including noncontrolling interest | 277,804 | 574,076 | 583,974 | 918,094 | |||||||||||||||||||
| Less: Net income attributable to noncontrolling interest | 22,462 | 45,648 | 38,701 | 152,445 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO MURPHY | $ | 255,342 | 528,428 | $ | 545,273 | 765,649 | |||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | 1.64 | 3.40 | $ | 3.50 | 4.94 | |||||||||||||||||
| Discontinued operations | — | — | — | (0.01) | |||||||||||||||||||
| Net income | $ | 1.64 | 3.40 | $ | 3.50 | 4.93 | |||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | 1.63 | 3.36 | $ | 3.47 | 4.87 | |||||||||||||||||
| Discontinued operations | — | — | — | (0.01) | |||||||||||||||||||
| Net income | $ | 1.63 | 3.36 | $ | 3.47 | 4.86 | |||||||||||||||||
| Cash dividends per common share | $ | 0.275 | 0.250 | $ | 0.827 | 0.575 | |||||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | 155,454 | 155,446 | 155,749 | 155,221 | |||||||||||||||||||
| Diluted | 156,829 | 157,336 | 157,135 | 157,407 | |||||||||||||||||||
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Operating Activities | |||||||||||||||||||||||
| Net income including noncontrolling interest | $ | 277,804 | 574,076 | $ | 583,974 | 918,094 | |||||||||||||||||
| Adjustments to reconcile net income to net cash provided by continuing operations activities | |||||||||||||||||||||||
| Loss from discontinued operations | 421 | 422 | 744 | 1,916 | |||||||||||||||||||
| Depreciation, depletion and amortization | 237,493 | 214,521 | 648,830 | 574,501 | |||||||||||||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | 11,292 | 1,122 | 107,825 | 35,224 | |||||||||||||||||||
| Amortization of undeveloped leases | 2,846 | 2,671 | 8,215 | 10,651 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,675 | 11,286 | 34,196 | 34,725 | |||||||||||||||||||
| Deferred income tax expense | 59,547 | 140,414 | 152,104 | 207,105 | |||||||||||||||||||
| Contingent consideration payment | — | — | (139,574) | — | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (31,367) | 7,113 | 98,451 | |||||||||||||||||||
| Mark-to-market (gain) loss on derivative instruments | — | (239,050) | — | (138,707) | |||||||||||||||||||
| Long-term non-cash compensation | 20,426 | 17,145 | 42,502 | 57,612 | |||||||||||||||||||
| Gain from sale of assets | (12) | (18,836) | (12) | (18,871) | |||||||||||||||||||
| Net (increase) decrease in non-cash working capital | (127,447) | 61,724 | (142,788) | (59,874) | |||||||||||||||||||
| Other operating activities, net | (37,978) | (14,643) | (97,395) | (42,101) | |||||||||||||||||||
| Net cash provided by continuing operations activities | 456,067 | 719,485 | 1,205,734 | 1,678,726 | |||||||||||||||||||
| Investing Activities | |||||||||||||||||||||||
| Property additions and dry hole costs | (207,542) | (248,043) | (902,295) | (800,868) | |||||||||||||||||||
| Acquisition of oil and natural gas properties | (22,773) | (79,111) | (22,773) | (125,602) | |||||||||||||||||||
| Proceeds from sales of property, plant and equipment | 102,913 | (2,176) | 102,913 | (2,129) | |||||||||||||||||||
| Net cash required by investing activities | (127,402) | (329,330) | (822,155) | (928,599) | |||||||||||||||||||
| Financing Activities | |||||||||||||||||||||||
| Borrowings on revolving credit facility | 100,000 | 200,000 | 300,000 | 300,000 | |||||||||||||||||||
| Repayment of revolving credit facility | (100,000) | (200,000) | (300,000) | (300,000) | |||||||||||||||||||
| Retirement of debt | (248,675) | (246,032) | (248,675) | (446,032) | |||||||||||||||||||
| Early redemption of debt cost | — | (1,981) | — | (5,419) | |||||||||||||||||||
| Repurchase of common stock | (75,023) | — | (75,023) | — | |||||||||||||||||||
| Contingent consideration payment | — | — | (60,243) | (81,742) | |||||||||||||||||||
| Cash dividends paid | (42,790) | (38,863) | (128,657) | (89,354) | |||||||||||||||||||
| Distributions to noncontrolling interest | (4,069) | (50,419) | (20,052) | (145,273) | |||||||||||||||||||
| Withholding tax on stock-based incentive awards | (12) | (641) | (14,232) | (17,338) | |||||||||||||||||||
| Capital lease obligation payments | (161) | (155) | (457) | (475) | |||||||||||||||||||
| Issue costs of debt facility | — | — | (20) | — | |||||||||||||||||||
| Net cash required by financing activities | (370,730) | (338,091) | (547,359) | (785,633) | |||||||||||||||||||
| Net cash required by discontinued operations | — | (14,500) | — | (14,500) | |||||||||||||||||||
| Effect of exchange rate changes on cash and cash equivalents | 479 | (3,585) | (414) | (5,180) | |||||||||||||||||||
| Net (decrease) increase in cash and cash equivalents | (41,586) | 33,979 | (164,194) | (55,186) | |||||||||||||||||||
| Cash and cash equivalents at beginning of period | 369,355 | 432,019 | 491,963 | 521,184 | |||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 327,769 | 465,998 | $ | 327,769 | 465,998 | |||||||||||||||||
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MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED NET INCOME (LOSS) (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 255.3 | 528.4 | $ | 545.3 | 765.6 | |||||||||||||||||
| Discontinued operations loss | 0.4 | 0.4 | 0.7 | 1.9 | |||||||||||||||||||
| Net income from continuing operations attributable to Murphy | 255.7 | 528.8 | 546.0 | 767.5 | |||||||||||||||||||
Adjustments 2: | |||||||||||||||||||||||
| Write-off of previously suspended exploration well | — | — | 17.1 | — | |||||||||||||||||||
| Foreign exchange (gain) | (8.6) | (20.7) | (0.3) | (28.7) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (31.3) | 7.1 | 98.5 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (239.0) | — | (138.7) | |||||||||||||||||||
| (Gain) on sale of assets | — | (15.2) | — | (15.2) | |||||||||||||||||||
| Early redemption of debt cost | — | 2.4 | — | 6.8 | |||||||||||||||||||
| Total adjustments, before taxes | (8.6) | (303.8) | 23.9 | (77.3) | |||||||||||||||||||
Income tax expense (benefit) related to adjustments | 2.2 | 64.7 | (1.4) | 17.3 | |||||||||||||||||||
| Total adjustments after taxes | (6.4) | (239.1) | 22.5 | (60.0) | |||||||||||||||||||
| Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 249.3 | 289.7 | $ | 568.5 | 707.5 | |||||||||||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 1.59 | 1.84 | $ | 3.62 | 4.49 | |||||||||||||||||
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 September 30, 2023 | Nine Months Ended September 30, 2023 | ||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Pretax | Tax | Net | Pretax | Tax | Net | |||||||||||||||||||||||||||||
Exploration & Production: | |||||||||||||||||||||||||||||||||||
| United States | $ | — | — | — | $ | 7.1 | (1.5) | 5.6 | |||||||||||||||||||||||||||
| Other | — | — | — | 17.1 | — | 17.1 | |||||||||||||||||||||||||||||
| Corporate | (8.6) | 2.2 | (6.4) | (0.3) | 0.1 | (0.3) | |||||||||||||||||||||||||||||
Total adjustments | $ | (8.6) | 2.2 | (6.4) | $ | 23.9 | (1.4) | 22.5 | |||||||||||||||||||||||||||
10
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION (EBITDA)
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 255.3 | 528.4 | $ | 545.3 | 765.6 | |||||||||||||||||
| Income tax expense | 78.1 | 159.5 | 166.8 | 247.6 | |||||||||||||||||||
| Interest expense, net | 30.0 | 37.4 | 88.7 | 116.1 | |||||||||||||||||||
Depreciation, depletion and amortization expense 2 | 231.5 | 207.7 | 630.8 | 552.5 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 594.9 | 933.0 | $ | 1,431.6 | 1,681.8 | |||||||||||||||||
| Write-off of previously suspended exploration well | — | — | 17.1 | — | |||||||||||||||||||
Accretion of asset retirement obligations 2 | 10.4 | 10.0 | 30.4 | 30.7 | |||||||||||||||||||
| Foreign exchange (gain) | (8.6) | (20.7) | (0.3) | (28.7) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (31.4) | 7.1 | 98.5 | |||||||||||||||||||
| Discontinued operations loss | 0.4 | 0.4 | 0.7 | 1.9 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (239.1) | — | (138.7) | |||||||||||||||||||
(Gain) on sale of assets 2 | — | (15.2) | — | (15.2) | |||||||||||||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 597.1 | 637.1 | $ | 1,486.6 | 1,630.3 | |||||||||||||||||
1 Excludes results attributable to a noncontrolling interest in MP GOM.
2 Depreciation, depletion, and amortization expense, 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.
11
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION AND EXPLORATION (EBITDAX)
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 255.3 | 528.4 | $ | 545.3 | 765.6 | |||||||||||||||||
| Income tax expense | 78.1 | 159.5 | 166.8 | 247.6 | |||||||||||||||||||
| Interest expense, net | 30.0 | 37.4 | 88.7 | 116.1 | |||||||||||||||||||
Depreciation, depletion and amortization expense 2 | 231.5 | 207.7 | 630.8 | 552.5 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | 594.9 | 933.0 | 1,431.6 | 1,681.8 | |||||||||||||||||||
Exploration expenses 2 | 23.0 | 9.5 | 122.6 | 72.2 | |||||||||||||||||||
| EBITDAX attributable to Murphy (Non-GAAP) | 617.9 | 942.5 | 1,554.2 | 1,754.0 | |||||||||||||||||||
Accretion of asset retirement obligations 2 | 10.4 | 10.0 | 30.4 | 30.7 | |||||||||||||||||||
| Foreign exchange (gain) | (8.6) | (20.7) | (0.3) | (28.7) | |||||||||||||||||||
| Mark-to-market (gain) loss on contingent consideration | — | (31.4) | 7.1 | 98.5 | |||||||||||||||||||
| Discontinued operations loss | 0.4 | 0.4 | 0.7 | 1.9 | |||||||||||||||||||
| Mark-to-market (gain) on derivative instruments | — | (239.1) | — | (138.7) | |||||||||||||||||||
(Gain) on sale of assets 2 | — | (15.2) | — | (15.2) | |||||||||||||||||||
| Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 620.1 | $ | 646.6 | $ | 1,592.1 | $ | 1,702.5 | |||||||||||||||
1 Excludes results attributable to a noncontrolling interest in MP GOM.
2 Depreciation, depletion, and amortization expense, accretion of asset retirement obligations, 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.
12
MURPHY OIL CORPORATION
FUNCTIONAL RESULTS OF OPERATIONS (unaudited)
| Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
United States 1 | $ | 823.7 | 310.3 | $ | 973.8 | 481.5 | ||||||||
| Canada | 129.3 | 10.5 | 209.6 | 41.4 | ||||||||||
| Other | 3.4 | (12.5) | 4.8 | (5.8) | ||||||||||
| Total exploration and production | 956.4 | 308.3 | 1,188.2 | 517.1 | ||||||||||
| Corporate | 3.2 | (30.1) | 115.2 | 57.4 | ||||||||||
| Continuing operations | 959.6 | 278.2 | 1,303.4 | 574.5 | ||||||||||
| Discontinued operations, net of tax | — | (0.4) | — | (0.4) | ||||||||||
| Total including noncontrolling interest | $ | 959.6 | 277.8 | $ | 1,303.4 | 574.1 | ||||||||
| Net income attributable to Murphy | 255.3 | 528.4 | ||||||||||||
| Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
United States 1 | $ | 2,202.2 | 705.2 | $ | 2,659.2 | 1,225.9 | ||||||||
| Canada | 403.3 | 34.9 | 582.3 | 111.3 | ||||||||||
| Other | 7.1 | (50.0) | 18.5 | (53.5) | ||||||||||
| Total exploration and production | 2,612.6 | 690.1 | 3,260.0 | 1,283.7 | ||||||||||
| Corporate | 3.3 | (105.4) | (302.6) | (363.7) | ||||||||||
| Continuing operations | 2,615.9 | 584.7 | 2,957.4 | 920.0 | ||||||||||
| Discontinued operations, net of tax | — | (0.7) | — | (1.9) | ||||||||||
| Total including noncontrolling interest | $ | 2,615.9 | 584.0 | $ | 2,957.4 | 918.1 | ||||||||
| Net income attributable to Murphy | 545.3 | 765.6 | ||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
13
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
THREE MONTHS ENDED SEPTEMBER 30, 2023, AND 2022
| (Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Three Months Ended September 30, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 823.7 | 121.4 | 3.4 | 948.5 | |||||||||
| Sales of purchased natural gas | — | 7.9 | — | 7.9 | ||||||||||
| Lease operating expenses | 153.2 | 39.5 | 0.7 | 193.4 | ||||||||||
| Severance and ad valorem taxes | 10.6 | 0.3 | — | 10.9 | ||||||||||
| Transportation, gathering and processing | 41.9 | 19.6 | — | 61.5 | ||||||||||
| Costs of purchased natural gas | — | 5.5 | — | 5.5 | ||||||||||
| Depreciation, depletion and amortization | 193.6 | 40.4 | 0.7 | 234.7 | ||||||||||
| Accretion of asset retirement obligations | 9.6 | 2.0 | 0.1 | 11.7 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 11.3 | — | — | 11.3 | ||||||||||
| Geological and geophysical | 1.9 | — | 2.4 | 4.3 | ||||||||||
| Other exploration | 2.4 | — | 5.6 | 8.0 | ||||||||||
| 15.6 | — | 8.0 | 23.6 | |||||||||||
| Undeveloped lease amortization | 2.1 | — | 0.7 | 2.8 | ||||||||||
| Total exploration expenses | 17.7 | — | 8.7 | 26.4 | ||||||||||
| Selling and general expenses | 3.4 | 4.3 | 3.0 | 10.7 | ||||||||||
| Other | 4.1 | 3.4 | 0.3 | 7.8 | ||||||||||
| Results of operations before taxes | 389.6 | 14.3 | (10.1) | 393.8 | ||||||||||
| Income tax provisions | 79.3 | 3.8 | 2.4 | 85.5 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 310.3 | 10.5 | (12.5) | 308.3 | |||||||||
| Three Months Ended September 30, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 973.8 | 164.1 | 4.8 | 1,142.7 | |||||||||
| Sales of purchased natural gas | — | 45.5 | — | 45.5 | ||||||||||
| Lease operating expenses | 158.8 | 39.6 | 0.3 | 198.7 | ||||||||||
| Severance and ad valorem taxes | 14.9 | 0.3 | — | 15.2 | ||||||||||
| Transportation, gathering and processing | 38.5 | 16.9 | — | 55.4 | ||||||||||
| Costs of purchased natural gas | — | 43.7 | — | 43.7 | ||||||||||
| Depreciation, depletion and amortization | 169.4 | 40.9 | 0.9 | 211.2 | ||||||||||
| Accretion of asset retirement obligations | 8.8 | 2.4 | — | 11.2 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 0.2 | — | 0.9 | 1.1 | ||||||||||
| Geological and geophysical | 1.1 | 0.1 | 0.4 | 1.6 | ||||||||||
| Other exploration | 1.5 | — | 2.6 | 4.1 | ||||||||||
| 2.8 | 0.1 | 3.9 | 6.8 | |||||||||||
| Undeveloped lease amortization | 2.0 | 0.1 | 0.6 | 2.7 | ||||||||||
| Total exploration expenses | 4.8 | 0.2 | 4.5 | 9.5 | ||||||||||
| Selling and general expenses | 2.6 | 5.2 | 2.0 | 9.8 | ||||||||||
| Other | (27.7) | 3.7 | 0.6 | (23.4) | ||||||||||
| Results of operations before taxes | 603.7 | 56.7 | (3.5) | 656.9 | ||||||||||
| Income tax provisions | 122.2 | 15.3 | 2.3 | 139.8 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 481.5 | 41.4 | (5.8) | 517.1 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
14
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
NINE MONTHS ENDED SEPTEMBER 30, 2023, AND 2022
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Nine Months Ended September 30, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 2,202.2 | 338.7 | 7.1 | 2,548.0 | |||||||||
| Sales of purchased natural gas | — | 64.6 | — | 64.6 | ||||||||||
| Lease operating expenses | 472.4 | 113.8 | 1.4 | 587.6 | ||||||||||
| Severance and ad valorem taxes | 34.1 | 1.0 | — | 35.1 | ||||||||||
| Transportation, gathering and processing | 119.1 | 56.2 | — | 175.3 | ||||||||||
| Costs of purchased natural gas | — | 47.4 | — | 47.4 | ||||||||||
| Depreciation, depletion and amortization | 531.8 | 107.0 | 1.6 | 640.4 | ||||||||||
| Accretion of asset retirement obligations | 28.0 | 5.8 | 0.3 | 34.1 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 90.9 | — | 16.9 | 107.8 | ||||||||||
| Geological and geophysical | 2.6 | 0.1 | 12.9 | 15.6 | ||||||||||
| Other exploration | 5.7 | 0.2 | 15.0 | 20.9 | ||||||||||
| 99.2 | 0.3 | 44.8 | 144.3 | |||||||||||
| Undeveloped lease amortization | 6.2 | 0.1 | 1.9 | 8.2 | ||||||||||
| Total exploration expenses | 105.4 | 0.4 | 46.7 | 152.5 | ||||||||||
| Selling and general expenses | 7.9 | 11.3 | 5.8 | 25.0 | ||||||||||
| Other | 14.1 | 13.2 | 1.7 | 29.0 | ||||||||||
| Results of operations before taxes | 889.4 | 47.2 | (50.4) | 886.2 | ||||||||||
Income tax provisions (benefits) | 184.2 | 12.3 | (0.4) | 196.1 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 705.2 | 34.9 | (50.0) | 690.1 | |||||||||
| Nine Months Ended September 30, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 2,659.0 | 450.2 | 18.5 | 3,127.7 | |||||||||
| Sales of purchased natural gas | 0.2 | 132.1 | — | 132.3 | ||||||||||
| Lease operating expenses | 368.2 | 113.4 | 1.2 | 482.8 | ||||||||||
| Severance and ad valorem taxes | 46.4 | 1.0 | — | 47.4 | ||||||||||
| Transportation, gathering and processing | 100.0 | 52.2 | — | 152.2 | ||||||||||
| Costs of purchased natural gas | 0.2 | 125.1 | — | 125.3 | ||||||||||
| Depreciation, depletion and amortization | 449.6 | 110.7 | 4.4 | 564.7 | ||||||||||
| Accretion of asset retirement obligations | 27.3 | 7.3 | 0.1 | 34.7 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | (0.5) | — | 35.7 | 35.2 | ||||||||||
| Geological and geophysical | 3.7 | 0.2 | 1.4 | 5.3 | ||||||||||
| Other exploration | 5.9 | 0.4 | 14.7 | 21.0 | ||||||||||
| 9.1 | 0.6 | 51.8 | 61.5 | |||||||||||
| Undeveloped lease amortization | 6.7 | 0.2 | 3.8 | 10.7 | ||||||||||
| Total exploration expenses | 15.8 | 0.8 | 55.6 | 72.2 | ||||||||||
| Selling and general expenses | 14.1 | 14.1 | 6.5 | 34.7 | ||||||||||
| Other | 110.4 | 6.5 | 1.0 | 117.9 | ||||||||||
| Results of operations before taxes | 1,527.2 | 151.2 | (50.3) | 1,628.1 | ||||||||||
Income tax provisions | 301.3 | 39.9 | 3.2 | 344.4 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 1,225.9 | 111.3 | (53.5) | 1,283.7 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
15
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Dollars per barrel of oil equivalents sold) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
United States – Eagle Ford Shale | |||||||||||||||||||||||
Lease operating expense | $ | 11.38 | 9.31 | $ | 12.42 | 10.87 | |||||||||||||||||
Severance and ad valorem taxes | 2.91 | 3.97 | 3.54 | 4.67 | |||||||||||||||||||
Depreciation, depletion and amortization (DD&A) expense | 26.35 | 25.57 | 26.35 | 25.63 | |||||||||||||||||||
United States – Gulf of Mexico1 | |||||||||||||||||||||||
| Lease operating expense | $ | 13.42 | 15.92 | $ | 14.27 | 12.62 | |||||||||||||||||
| Severance and ad valorem taxes | 0.06 | 0.06 | 0.07 | 0.08 | |||||||||||||||||||
DD&A expense | 12.05 | 9.82 | 11.57 | 9.75 | |||||||||||||||||||
Canada – Onshore | |||||||||||||||||||||||
Lease operating expense | $ | 5.33 | 5.48 | $ | 5.97 | 6.46 | |||||||||||||||||
Severance and ad valorem taxes | 0.05 | 0.05 | 0.06 | 0.06 | |||||||||||||||||||
DD&A expense | 5.53 | 5.73 | 5.70 | 6.36 | |||||||||||||||||||
Canada – Offshore | |||||||||||||||||||||||
| Lease operating expense | $ | 12.12 | 15.43 | $ | 12.45 | 14.19 | |||||||||||||||||
DD&A expense | 10.02 | 14.39 | 9.59 | 12.72 | |||||||||||||||||||
| Total E&P continuing operations | |||||||||||||||||||||||
| Lease operating expense | $ | 10.12 | 10.88 | $ | 11.16 | 10.22 | |||||||||||||||||
Severance and ad valorem taxes | 0.57 | 0.83 | 0.67 | 1.00 | |||||||||||||||||||
DD&A expense | 12.43 | 11.75 | 12.33 | 12.15 | |||||||||||||||||||
| Total oil and gas continuing operations – excluding noncontrolling interest | |||||||||||||||||||||||
Lease operating expense | $ | 9.94 | 10.64 | $ | 10.98 | 10.07 | |||||||||||||||||
Severance and ad valorem taxes | 0.59 | 0.86 | 0.69 | 1.05 | |||||||||||||||||||
DD&A expense | 12.50 | 11.85 | 12.41 | 12.29 | |||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
16
MURPHY OIL CORPORATION
CAPITAL EXPENDITURES
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
United States1 | $ | 143.9 | 259.5 | $ | 644.0 | 677.7 | |||||||||||||||||
| Canada | 27.1 | 25.0 | 170.6 | 175.9 | |||||||||||||||||||
| Other | 11.0 | 8.2 | 55.7 | 50.5 | |||||||||||||||||||
| Total | 182.0 | 292.7 | 870.3 | 904.1 | |||||||||||||||||||
| Corporate | 5.5 | 3.4 | 15.4 | 13.9 | |||||||||||||||||||
Total capital expenditures - continuing operations2 | 187.5 | 296.1 | 885.7 | 918.0 | |||||||||||||||||||
Charged to exploration expenses3 | |||||||||||||||||||||||
United States1 | 15.5 | 2.8 | 99.2 | 9.1 | |||||||||||||||||||
| Canada | 0.1 | 0.1 | 0.3 | 0.6 | |||||||||||||||||||
| Other | 8.0 | 3.9 | 44.8 | 51.8 | |||||||||||||||||||
| Total charged to exploration expenses - continuing operations | 23.6 | 6.8 | 144.3 | 61.5 | |||||||||||||||||||
| Total capitalized | $ | 163.9 | 289.3 | $ | 741.4 | 856.5 | |||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the three months ended September 30, 2023, total capital expenditures excluding acquisition-related costs of $7.5 million (Côte d’Ivoire and Vietnam) (2022: $79.1 million) and noncontrolling interest (NCI) of $18.4 million (2022: $8.0 million) is $161.6 million (2022: $209.0 million). For the nine months ended September 30, 2023, total capital expenditures excluding acquisition-related costs of $39.8 million (Côte d’Ivoire and Vietnam) (2022:$125.6 million) and noncontrolling interest (NCI) of $57.2 million (2022: $16.6 million) is $788.7 million (2022: $775.8 million).
3 For the three and nine months ended ended September 30, 2023, charges to exploration expense excludes amortization of undeveloped leases of $2.8 million (2022: $2.7 million) and $8.2 million (2022 $10.7 million), respectively. For the three months ended September 30, 2023, charges to exploration expense excluding NCI of $3.6 million (2022: $0) is $20 million. For the nine months ended September 30, 2023, charges to exploration expense excluding previously suspended exploration costs of $17.1 million (2022: $0) and NCI of $29.9 million (2022: $0) is $97.3 million.
17
MURPHY OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited)
| (Thousands of dollars) | September 30, 2023 | December 31, 2022 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 327,769 | 491,963 | ||||||||
Accounts receivable, net | 460,630 | 391,152 | |||||||||
| Inventories | 60,435 | 54,513 | |||||||||
| Prepaid expenses | 38,177 | 34,697 | |||||||||
| Total current assets | 887,011 | 972,325 | |||||||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization | 8,218,015 | 8,228,016 | |||||||||
| Operating lease assets | 792,149 | 946,406 | |||||||||
| Deferred income taxes | 1,111 | 117,889 | |||||||||
| Deferred charges and other assets | 44,292 | 44,316 | |||||||||
| Total assets | $ | 9,942,578 | 10,308,952 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current maturities of long-term debt, finance lease | $ | 714 | 687 | ||||||||
| Accounts payable | 449,960 | 543,786 | |||||||||
| Income taxes payable | 24,000 | 26,544 | |||||||||
| Other taxes payable | 34,335 | 22,819 | |||||||||
| Operating lease liabilities | 245,884 | 220,413 | |||||||||
| Other accrued liabilities | 137,500 | 443,585 | |||||||||
| Total current liabilities | 892,393 | 1,257,834 | |||||||||
| Long-term debt, including finance lease obligation | 1,576,279 | 1,822,452 | |||||||||
| Asset retirement obligations | 859,123 | 817,268 | |||||||||
| Deferred credits and other liabilities | 289,962 | 304,948 | |||||||||
| Non-current operating lease liabilities | 561,254 | 742,654 | |||||||||
| Deferred income taxes | 250,768 | 214,903 | |||||||||
| Total liabilities | 4,429,779 | 5,160,059 | |||||||||
| Equity | |||||||||||
Common Stock, par $1.00 | 195,101 | 195,101 | |||||||||
| Capital in excess of par value | 869,132 | 893,578 | |||||||||
| Retained earnings | 6,472,114 | 6,055,498 | |||||||||
| Accumulated other comprehensive loss | (533,940) | (534,686) | |||||||||
| Treasury stock | (1,662,376) | (1,614,717) | |||||||||
| Murphy Shareholders' Equity | 5,340,031 | 4,994,774 | |||||||||
| Noncontrolling interest | 172,768 | 154,119 | |||||||||
| Total equity | 5,512,799 | 5,148,893 | |||||||||
| Total liabilities and equity | $ | 9,942,578 | 10,308,952 | ||||||||
18
MURPHY OIL CORPORATION
PRODUCTION SUMMARY
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
United States - Onshore | 27,772 | 28,522 | 24,674 | 25,082 | ||||||||||||||||||||||
United States - Gulf of Mexico 1 | 74,843 | 68,315 | 74,185 | 62,380 | ||||||||||||||||||||||
Canada - Onshore | 2,935 | 3,891 | 3,104 | 4,228 | ||||||||||||||||||||||
Canada - Offshore | 2,956 | 2,171 | 2,778 | 2,869 | ||||||||||||||||||||||
| Other | 262 | 487 | 247 | 716 | ||||||||||||||||||||||
Total net crude oil and condensate | 108,768 | 103,386 | 104,988 | 95,275 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
United States - Onshore | 5,272 | 5,782 | 4,590 | 5,268 | ||||||||||||||||||||||
United States - Gulf of Mexico 1 | 5,882 | 4,780 | 6,170 | 4,411 | ||||||||||||||||||||||
Canada - Onshore | 732 | 986 | 705 | 942 | ||||||||||||||||||||||
Total net natural gas liquids | 11,886 | 11,548 | 11,465 | 10,621 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
United States - Onshore | 28,312 | 30,054 | 25,571 | 29,032 | ||||||||||||||||||||||
United States - Gulf of Mexico 1 | 70,240 | 65,319 | 71,764 | 61,727 | ||||||||||||||||||||||
Canada - Onshore | 426,725 | 392,483 | 361,852 | 313,422 | ||||||||||||||||||||||
Total net natural gas | 525,277 | 487,856 | 459,187 | 404,181 | ||||||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 208,200 | 196,243 | 192,984 | 173,260 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,989) | (7,125) | (6,181) | (7,735) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (191) | (264) | (209) | (290) | ||||||||||||||||||||||
Net natural gas – thousands of cubic feet per day | (1,887) | (2,202) | (1,996) | (2,628) | ||||||||||||||||||||||
Total noncontrolling interest 2,3 | (6,495) | (7,756) | (6,723) | (8,463) | ||||||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 201,705 | 188,487 | 186,261 | 164,797 | ||||||||||||||||||||||
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.
19
MURPHY OIL CORPORATION
WEIGHTED AVERAGE PRICE SUMMARY
(unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | |||||||||||||||||||||||
United States - Onshore | $ | 81.19 | 94.33 | $ | 76.40 | 99.92 | |||||||||||||||||
United States - Gulf of Mexico 1 | 82.94 | 92.96 | 76.73 | 99.04 | |||||||||||||||||||
Canada - Onshore 2 | 76.33 | 82.25 | 73.01 | 92.31 | |||||||||||||||||||
Canada - Offshore 2 | 94.85 | 111.76 | 84.13 | 112.93 | |||||||||||||||||||
Other 2 | 77.19 | 117.18 | 82.87 | 92.91 | |||||||||||||||||||
| Natural gas liquids – dollars per barrel | |||||||||||||||||||||||
| United States - Onshore | 20.52 | 34.33 | 19.76 | 36.83 | |||||||||||||||||||
United States - Gulf of Mexico 1 | 20.16 | 36.56 | 22.01 | 39.99 | |||||||||||||||||||
Canada - Onshore 2 | 37.72 | 54.40 | 39.08 | 57.53 | |||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | |||||||||||||||||||||||
| United States - Onshore | 2.32 | 7.62 | 2.24 | 6.49 | |||||||||||||||||||
United States - Gulf of Mexico 1 | 2.84 | 8.68 | 2.82 | 7.23 | |||||||||||||||||||
Canada - Onshore 2 | 1.93 | 2.75 | 2.07 | 2.70 | |||||||||||||||||||
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
20
MURPHY OIL CORPORATION
FIXED PRICE FORWARD SALES AND COMMODITY HEDGE POSITIONS (unaudited)
AS OF OCTOBER 31, 2023
| Volumes (MMcf/d) | Price/MCF | Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type 1 | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 250 | C$2.35 | 10/1/2023 | 12/31/2023 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 25 | US$1.98 | 10/1/2023 | 10/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 162 | C$2.39 | 1/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 15 | US$1.98 | 11/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
1 Fixed price forward sale contracts are accounted for as normal sales and purchases for accounting purposes.
21
MURPHY OIL CORPORATION
FOURTH QUARTER 2023 GUIDANCE
| Oil BOPD | NGLs BOPD | Gas MCFD | Total BOEPD | ||||||||||||||||||||
| Production – net | |||||||||||||||||||||||
| U.S. – Eagle Ford Shale | 22,800 | 5,000 | 27,300 | 32,400 | |||||||||||||||||||
| – Gulf of Mexico excluding NCI | 66,300 | 4,800 | 64,000 | 81,800 | |||||||||||||||||||
| Canada – Tupper Montney | — | — | 380,300 | 63,400 | |||||||||||||||||||
| – Kaybob Duvernay and Placid Montney | 2,000 | 500 | 7,700 | 3,800 | |||||||||||||||||||
| – Offshore | 3,800 | — | — | 3,800 | |||||||||||||||||||
| Other | 300 | — | — | 300 | |||||||||||||||||||
Total net production (BOEPD) - excluding NCI 1 | 181,500 to 189,500 | ||||||||||||||||||||||
| Exploration expense ($ millions) | $53 | ||||||||||||||||||||||
| FULL YEAR 2023 GUIDANCE | |||||||||||||||||||||||
Total net production (BOEPD) - excluding NCI 2 | 185,000 to 187,000 | ||||||||||||||||||||||
Capital expenditures – excluding NCI ($ millions) 3 | $950 to $1,025 | ||||||||||||||||||||||
| ¹ Excludes noncontrolling interest of MP GOM of 6,400 BOPD of oil, 200 BOPD of NGLs, and 2,700 MCFD gas. | |||||||||||||||||||||||
| ² Excludes noncontrolling interest of MP GOM of 6,200 BOPD of oil, 200 BOPD of NGLs, and 2,200 MCFD gas. | |||||||||||||||||||||||
| ³ Excludes noncontrolling interest of MP GOM of $70 million and acquisition-related costs of $49 million. | |||||||||||||||||||||||
22