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): August 3, 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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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 August 3, 2023 Murphy Oil Corporation issued a news release announcing its financial and operating results for the quarter ended June 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: August 3, 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 SECOND QUARTER 2023 FINANCIAL AND OPERATING RESULTS, STRATEGIC PORTFOLIO REPOSITIONING
Exceeded Upper End of Guidance Range With Production of 184 MBOEPD,
Signed Production Sharing Contracts for Côte d’Ivoire New Country Entry,
Executed Agreement to Divest Non-Core Canadian Assets
HOUSTON, Texas, August 3, 2023 – Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the second quarter ended June 30, 2023, including net income attributable to Murphy of $98 million, or $0.62 net income per diluted share. Excluding discontinued operations and other items affecting comparability between periods, adjusted net income attributable to Murphy was $124 million, or $0.79 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 second quarter include:
•Exceeded upper end of guidance range with production of 184 thousand barrels of oil equivalent per day (MBOEPD), including 99 thousand barrels of oil per day (MBOPD)
•Received government approval on Block 15-1/05 Lac Da Vang field development plan in Vietnam
•Signed production sharing contracts (PSCs) for five blocks offshore Côte d’Ivoire
Subsequent to the second quarter:
•Signed a Purchase and Sale Agreement to divest a portion of Kaybob Duvernay and Placid Montney assets for C$150 million net purchase price
•Published the fifth annual Sustainability Report with enhanced disclosures on improved environmental activities, increased community support and continuing strong governance oversight
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“Murphy’s operational excellence continues to shine as our portfolio again outperformed expectations this quarter. From offshore maintenance being completed faster than scheduled to onshore wells achieving production rates above type curves, our team has done a great job executing our 2023 plan. We also have exciting opportunities ahead, including advancing the Vietnam Lac Da Vang field development plan towards project sanction as well as evaluating our new Côte d’Ivoire acreage. I look forward to progressing our capital allocation framework this year with increasing returns to shareholders and additional debt reduction, which will be supported by monetizing a non-core portion of our Canadian assets,” said Roger W. Jenkins, President and Chief Executive Officer. “Additionally, Murphy continues to operate sustainably, and we were recently recognized by Rystad Energy as the highest-scoring company in ESG performance for the 2021 reporting year across 41 operators in the United States and Canada.”
SECOND QUARTER 2023 RESULTS
The company recorded net income attributable to Murphy of $98 million, or $0.62 net income per diluted share, for the second 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 $124 million, or $0.79 adjusted net income per diluted share for the same period. Adjustments to net income total $28 million before tax. Details for second quarter results and an adjusted net income reconciliation can be found in the attached schedules.
Including NCI, second quarter 2023 exploration expense of $116 million contains three primary items: $80 million of dry hole expense for the Chinook #7 exploration well in the Gulf of Mexico, inclusive of $26 million attributable to NCI; a $17 million write-off of the previously suspended Cholula-1EXP exploration well in offshore Mexico; and $10 million in seismic costs for the Côte d’Ivoire new country entry.
Earnings before interest, taxes, depreciation and amortization (EBITDA) attributable to Murphy were $373 million. Earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) attributable to Murphy were $463 million. Adjusted EBITDA attributable to Murphy was $412 million. Adjusted EBITDAX attributable to Murphy was $485 million. Reconciliations for second quarter EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX can be found in the attached schedules.
In the second quarter, Murphy paid the final contingent consideration payments of $28 million related to the Gulf of Mexico acquisition that closed in 2019. This amount was primarily
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attributable to the one-year anniversary of achieving first oil at King’s Quay. Murphy has no remaining contingent consideration payment obligations.
Second quarter production averaged 184 MBOEPD and consisted of 54 percent oil volumes, or 99 MBOPD. Production for the quarter exceeded the upper end of the guidance range, primarily driven by 2.5 MBOEPD of strong well performance in the Gulf of Mexico, 2.1 MBOEPD in the Tupper Montney and 1.5 MBOEPD in the Eagle Ford Shale, as well as 1.4 MBOEPD attributed to lower realized royalty rates in the Tupper Montney natural gas asset. Details for second quarter production can be found in the attached schedules.
FINANCIAL POSITION
Murphy had approximately $1.1 billion of liquidity on June 30, 2023, with no borrowings on the $800 million credit facility and $369 million of cash and cash equivalents, inclusive of NCI.
On June 30, 2023, the company’s total debt was unchanged from year-end 2022 at $1.82 billion, and consisted of long-term, fixed-rate notes with a weighted average maturity of 7.2 years and a weighted average coupon of 6.1 percent.
CANADA TRANSACTION SUMMARY
Subsequent to quarter end, a subsidiary of Murphy signed a Purchase and Sale Agreement to divest a non-core portion of its operated Kaybob Duvernay assets and all of its non-operated Placid Montney assets to a private company. Under the terms of the agreement, the buyer will pay Murphy C$150 million at closing in an all-cash transaction, subject to customary closing adjustments and conditions. The transaction has a March 1, 2023 effective date, with closing anticipated to occur in the third quarter of 2023.
The assets to be divested include the Saxon and Simonette areas of the Kaybob Duvernay, where Murphy holds a 70 percent working interest as operator, as well as Murphy’s 30 percent working interest in the Placid Montney assets operated by Athabasca Oil Corporation. Also included are batteries, pipelines and the assumption of related processing and marketing contracts.
The combined assets currently produce approximately 1,700 barrels of oil equivalent per day (BOEPD) net and are comprised of 39 percent oil. Net proved reserves are 5.3 million barrels of oil equivalent (MMBOE) as of December 31, 2022. Also included are 250 gross drilling locations, or 138 net, across 42,000 net acres in Kaybob Duvernay and 26,000 net acres in Placid Montney. After the transaction closes, Murphy will have approximately 488 gross drilling locations with an average 75 percent oil weighting remaining in the Kaybob Duvernay, all of
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which are operated with a 70 percent working interest. Murphy will have no remaining position in the Placid Montney.
“This transaction brings forward the value of a small, non-core portion of our onshore Canadian portfolio, as we were not planning to develop these locations for many years. I look forward to progressing our capital allocation framework goals in Murphy 2.0 with the proceeds from this divestiture, and continuing to reward our supportive, long-term shareholders in the upcoming quarters,” said Jenkins.
OPERATIONS SUMMARY
Onshore
In the second quarter of 2023, the onshore business produced approximately 98 MBOEPD, which included 36 percent liquids volumes.
Eagle Ford Shale – Production averaged 35 MBOEPD with 76 percent oil volumes and 89 percent liquids volumes. As planned, during the second quarter Murphy brought nine Catarina and eight Tilden operated wells online. Murphy continues to see stronger performance from completion design improvements across its well locations, including promising results in its new Tilden wells with an average gross 30-day (IP30) rate of approximately 1,200 BOEPD with 85 percent oil.
Tupper Montney – Natural gas production averaged 341 million cubic feet per day (MMCFD) in the second quarter, with 10 operated wells brought online. Of those wells, seven were brought on early that were originally planned for the third quarter. Production for the quarter exceeded guidance by 21 MMCFD, which included 13 MMCFD of improved well performance as Murphy realized its highest initial production rates in Tupper Montney history, as well as an 8 MMCFD benefit from a lower realized royalty rate of 2.4 percent.
“Our new onshore well completion design, developed within the last three years, is paying off with higher initial production rates,” said Jenkins. “With this new design, we have achieved continued exceptional results from new wells in both our Eagle Ford Shale and Tupper Montney assets.”
Kaybob Duvernay – During the second quarter, production averaged 4 MBOEPD with 60 percent liquids volumes. Production was minimally impacted from wildfires during the quarter, and no damage was sustained to facilities.
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Offshore
Excluding NCI, the offshore business produced approximately 87 MBOEPD for the second quarter, which included 80 percent oil.
Gulf of Mexico – Production averaged approximately 84 MBOEPD, consisting of 79 percent oil during the second quarter. Facility maintenance was completed as planned during the quarter, with work at King’s Quay concluded ahead of schedule.
Canada – In the second quarter, production averaged 3 MBOEPD, consisting of 100 percent oil. 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 – As previously disclosed, during the second quarter Murphy received government approval of the Block 15-1/05 Lac Da Vang field development plan in the Cuu Long Basin. Murphy holds a 40 percent working interest as operator of the block. PetroVietnam Exploration Production Corporation Limited and SK Earthon Co., Ltd. hold the remaining 35 percent and 25 percent working interest, respectively. Murphy is working to advance the development project in preparation for final review and sanction in late 2023.
EXPLORATION
Côte d’Ivoire – During the second quarter, Murphy signed production sharing contracts to secure working interests as operator in five deepwater blocks in the Tano Basin offshore Côte d’Ivoire. Murphy will initially hold a 90 percent working interest in four blocks, with an 85 percent working interest in the fifth block. Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire (PETROCI) holds the remaining working interest for each block.
Included in Block CI-103 is the Paon discovery, which was appraised with multiple wells by a previous operator. The PSC for the block includes a commitment to formulate and submit a viable field development plan for this discovery by the end of 2025.
“We are excited for our new country entry as an operator in Côte d’Ivoire, and are pleased with the competitive terms and low entry cost,” said Jenkins. “These blocks offer tremendous opportunities for exploration, and we look forward to maturing geophysical studies in this area and working with PETROCI on the possible development of the Paon discovery.”
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Gulf of Mexico – Following the quarter, Murphy, as operator of its subsidiary MP Gulf of Mexico, LLC, concluded drilling the Chinook #7 exploration well in Walker Ridge 425. The well encountered non-commercial hydrocarbons. Murphy plugged and abandoned the well, and approximately $80 million of the well cost before tax, inclusive of $26 million attributable to NCI, was expensed in the second quarter. Murphy holds a 66.66 percent working interest in the well.
As previously announced, during the second quarter Murphy, as operator, drilled a discovery at the Longclaw #1 exploration well. The company holds a 14.5 percent working interest in the well. The well reached a total measured depth of 25,106 feet at a net cost of approximately $6 million. The well encountered approximately 62 feet of net oil pay and is undergoing further evaluation.
Also during the quarter, Murphy was awarded five exploration blocks from the Gulf of Mexico Federal Lease Sale 259 with an average working interest of 90 percent.
Mexico – In conjunction with the July 2023 expiration of the Cholula appraisal period, Murphy wrote off previously suspended exploration well costs of $17 million.
2023 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Second quarter accrued capital expenditures (CAPEX) of $300 million, excluding lease acquisition costs, was lower than guidance due to timing of non-operated activity. Murphy accrued a total of $32 million in acquisition-related costs during the quarter, which will be paid in third quarter 2023.
Murphy is tightening its 2023 accrued CAPEX range to $950 million to $1.025 billion, which excludes $45 million in acquisition-related CAPEX for Côte d’Ivoire and Vietnam.
The company is raising its full year 2023 production range of 180 to 186 MBOEPD, consisting of approximately 53 percent oil and 59 percent liquids volumes.
Production for third quarter 2023 is estimated to be in the range of 188 to 196 MBOEPD with 99 MBOPD, or 52 percent, oil volumes. This range includes assumed Gulf of Mexico storm downtime of 4.6 MBOEPD, as well as operated planned downtime of 2.3 MBOEPD onshore and 600 BOEPD offshore. Murphy forecasts third quarter accrued CAPEX of $215 million, excluding acquisition-related costs.
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Both production and CAPEX guidance ranges exclude NCI. Production guidance will be adjusted following closing of the Canadian divestiture announced today.
Detailed guidance for the third quarter and full year 2023 is contained in the attached schedules.
FIXED PRICE FORWARD SALES CONTRACTS
Murphy maintains fixed price forward sales contracts tied to AECO pricing points 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 AUGUST 3, 2023
Murphy will host a conference call to discuss second quarter 2023 financial and operating results on Thursday, August 3, 2023, at 9:00 a.m. EDT. The call can be accessed either via the Internet through the Investor Relations section of Murphy Oil’s website at http://ir.murphyoilcorp.com or via the telephone by dialing toll free 1-888-886-7786, reservation number 24655854.
FINANCIAL DATA
Summary financial data and operating statistics for second 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 reconciliation of EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX between periods, as well as guidance for the third 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
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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.
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,
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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 report. 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
Nathan Shanor, 713-941-9576
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MURPHY OIL CORPORATION
SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | 799,836 | 1,146,299 | $ | 1,596,067 | 1,980,827 | |||||||||||||||||
| Sales of purchased natural gas | 13,014 | 49,939 | 56,751 | 86,785 | |||||||||||||||||||
| Total revenue from sales to customers | 812,850 | 1,196,238 | 1,652,818 | 2,067,612 | |||||||||||||||||||
| Loss on derivative instruments | — | (103,068) | — | (423,845) | |||||||||||||||||||
| Gain on sale of assets and other income | 1,738 | 7,887 | 3,486 | 10,251 | |||||||||||||||||||
| Total revenues and other income | 814,588 | 1,101,057 | 1,656,304 | 1,654,018 | |||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 194,292 | 147,352 | 394,276 | 284,177 | |||||||||||||||||||
| Severance and ad valorem taxes | 12,765 | 17,565 | 24,205 | 32,200 | |||||||||||||||||||
| Transportation, gathering and processing | 59,868 | 49,948 | 113,790 | 96,871 | |||||||||||||||||||
| Costs of purchased natural gas | 9,657 | 47,971 | 41,926 | 81,636 | |||||||||||||||||||
| Exploration expenses, including undeveloped lease amortization | 115,793 | 15,151 | 125,975 | 62,717 | |||||||||||||||||||
| Selling and general expenses | 25,345 | 27,130 | 43,653 | 60,659 | |||||||||||||||||||
| Depreciation, depletion and amortization | 215,667 | 195,856 | 411,337 | 359,980 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,364 | 11,563 | 22,521 | 23,439 | |||||||||||||||||||
| Other operating expense | 4,960 | 36,913 | 16,948 | 142,855 | |||||||||||||||||||
| Total costs and expenses | 649,711 | 549,449 | 1,194,631 | 1,144,534 | |||||||||||||||||||
| Operating income from continuing operations | 164,877 | 551,608 | 461,673 | 509,484 | |||||||||||||||||||
| Other income (loss) | |||||||||||||||||||||||
| Other (expenses) income | (7,694) | 5,308 | (7,767) | 2,813 | |||||||||||||||||||
| Interest expense, net | (29,856) | (41,385) | (58,711) | (78,662) | |||||||||||||||||||
| Total other loss | (37,550) | (36,077) | (66,478) | (75,849) | |||||||||||||||||||
| Income from continuing operations before income taxes | 127,327 | 515,531 | 395,195 | 433,635 | |||||||||||||||||||
| Income tax expense | 34,870 | 105,084 | 88,703 | 88,123 | |||||||||||||||||||
| Income from continuing operations | 92,457 | 410,447 | 306,492 | 345,512 | |||||||||||||||||||
| Loss from discontinued operations, net of income taxes | (602) | (943) | (323) | (1,494) | |||||||||||||||||||
| Net income including noncontrolling interest | 91,855 | 409,504 | 306,169 | 344,018 | |||||||||||||||||||
| Less: Net (loss) income attributable to noncontrolling interest | (6,431) | 58,947 | 16,239 | 106,797 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO MURPHY | $ | 98,286 | 350,557 | $ | 289,930 | 237,221 | |||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | 0.63 | 2.27 | $ | 1.86 | 1.54 | |||||||||||||||||
| Discontinued operations | — | (0.01) | — | (0.01) | |||||||||||||||||||
| Net income | $ | 0.63 | 2.26 | $ | 1.86 | 1.53 | |||||||||||||||||
| INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | 0.62 | 2.24 | $ | 1.84 | 1.51 | |||||||||||||||||
| Discontinued operations | — | (0.01) | — | (0.01) | |||||||||||||||||||
| Net income | $ | 0.62 | 2.23 | $ | 1.84 | 1.50 | |||||||||||||||||
| Cash dividends per common share | $ | 0.275 | 0.175 | $ | 0.550 | 0.325 | |||||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | 156,127 | 155,389 | 155,976 | 155,121 | |||||||||||||||||||
| Diluted | 157,299 | 157,455 | 157,308 | 157,852 | |||||||||||||||||||
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Operating Activities | |||||||||||||||||||||||
| Net income including noncontrolling interest | $ | 91,855 | 409,504 | $ | 306,169 | 344,018 | |||||||||||||||||
| Adjustments to reconcile net income to net cash provided by continuing operations activities | |||||||||||||||||||||||
| Loss from discontinued operations | 602 | 943 | 323 | 1,494 | |||||||||||||||||||
| Depreciation, depletion and amortization | 215,667 | 195,856 | 411,337 | 359,980 | |||||||||||||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | 95,682 | 1,271 | 96,533 | 34,102 | |||||||||||||||||||
| Amortization of undeveloped leases | 2,716 | 3,782 | 5,369 | 7,980 | |||||||||||||||||||
| Accretion of asset retirement obligations | 11,364 | 11,563 | 22,521 | 23,439 | |||||||||||||||||||
| Deferred income tax expense | 43,515 | 86,944 | 92,557 | 66,691 | |||||||||||||||||||
| Contingent consideration payment | (15,609) | — | (139,574) | — | |||||||||||||||||||
| Mark-to-market loss on contingent consideration | 3,175 | 31,692 | 7,113 | 129,818 | |||||||||||||||||||
| Mark-to-market (gain) loss on derivative instruments | — | (88,166) | — | 100,343 | |||||||||||||||||||
| Long-term non-cash compensation | 13,540 | 23,179 | 22,076 | 40,467 | |||||||||||||||||||
| (Gain) from sale of assets | — | (35) | — | (35) | |||||||||||||||||||
| Net decrease (increase) in non-cash working capital | 59,691 | (40,676) | (15,340) | (121,598) | |||||||||||||||||||
| Other operating activities, net | (52,307) | (14,946) | (59,417) | (27,458) | |||||||||||||||||||
| Net cash provided by continuing operations activities | 469,891 | 620,911 | 749,667 | 959,241 | |||||||||||||||||||
| Investing Activities | |||||||||||||||||||||||
| Property additions and dry hole costs | (349,434) | (307,917) | (694,753) | (552,825) | |||||||||||||||||||
| Acquisition of oil and natural gas properties | — | (46,491) | — | (46,491) | |||||||||||||||||||
| Proceeds from sales of property, plant and equipment | — | 47 | — | 47 | |||||||||||||||||||
| Net cash required by investing activities | (349,434) | (354,361) | (694,753) | (599,269) | |||||||||||||||||||
| Financing Activities | |||||||||||||||||||||||
| Borrowings on revolving credit facility | 100,000 | 100,000 | 200,000 | 100,000 | |||||||||||||||||||
| Repayment of revolving credit facility | (100,000) | (100,000) | (200,000) | (100,000) | |||||||||||||||||||
| Retirement of debt | — | (200,000) | — | (200,000) | |||||||||||||||||||
| Early redemption of debt cost | — | (3,438) | — | (3,438) | |||||||||||||||||||
| Distributions to noncontrolling interest | (6,304) | (54,970) | (15,983) | (94,854) | |||||||||||||||||||
| Contingent consideration payment | (12,565) | (26,573) | (60,243) | (81,742) | |||||||||||||||||||
| Issue costs of debt facility | (3) | — | (20) | — | |||||||||||||||||||
| Cash dividends paid | (42,942) | (27,191) | (85,867) | (50,491) | |||||||||||||||||||
| Withholding tax on stock-based incentive awards | (3) | (1,276) | (14,220) | (16,697) | |||||||||||||||||||
| Capital lease obligation payments | (157) | (162) | (296) | (320) | |||||||||||||||||||
| Net cash required by financing activities | (61,974) | (313,610) | (176,629) | (447,542) | |||||||||||||||||||
| Effect of exchange rate changes on cash and cash equivalents | (1,511) | (1,508) | (893) | (1,595) | |||||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 56,972 | (48,568) | (122,608) | (89,165) | |||||||||||||||||||
| Cash and cash equivalents at beginning of period | 312,383 | 480,587 | 491,963 | 521,184 | |||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 369,355 | 432,019 | $ | 369,355 | 432,019 | |||||||||||||||||
12
MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED NET INCOME (LOSS) (unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income attributable to Murphy (GAAP) | $ | 98.3 | 350.6 | $ | 289.9 | 237.2 | |||||||||||||||||
| Discontinued operations loss | 0.6 | 0.9 | 0.3 | 1.5 | |||||||||||||||||||
| Net income (loss) from continuing operations attributable to Murphy | 98.9 | 351.5 | 290.2 | 238.7 | |||||||||||||||||||
Adjustments1: | |||||||||||||||||||||||
| Write-off of previously suspended exploration well | 17.1 | — | 17.1 | — | |||||||||||||||||||
| Foreign exchange (gain) loss | 7.9 | (8.0) | 8.3 | (8.0) | |||||||||||||||||||
| Mark-to-market loss on contingent consideration | 3.2 | 31.7 | 7.1 | 129.8 | |||||||||||||||||||
| Mark-to-market (gain) loss on derivative instruments | — | (88.2) | — | 100.3 | |||||||||||||||||||
| Early redemption of debt cost | — | 4.4 | — | 4.4 | |||||||||||||||||||
| Total adjustments, before taxes | 28.2 | (60.1) | 32.5 | 234.5 | |||||||||||||||||||
| Income tax expense (benefit) related to adjustments | 2.7 | (13.2) | 3.6 | 47.4 | |||||||||||||||||||
| Total adjustments after taxes | 25.5 | (46.9) | 28.9 | 179.1 | |||||||||||||||||||
| Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 124.4 | 304.6 | $ | 319.1 | 417.8 | |||||||||||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 0.79 | 1.93 | $ | 2.03 | 2.65 | |||||||||||||||||
1 Certain prior-period amounts have been updated 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 June 30, 2023 | Six Months Ended June 30, 2023 | ||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Pretax | Tax | Net | Pretax | Tax | Net | |||||||||||||||||||||||||||||
Exploration & Production: | |||||||||||||||||||||||||||||||||||
| United States | $ | 3.2 | 0.7 | 2.5 | $ | 7.1 | 1.5 | 5.6 | |||||||||||||||||||||||||||
| Other | 17.1 | — | 17.1 | 17.1 | — | 17.1 | |||||||||||||||||||||||||||||
| Corporate | 7.9 | 2.0 | 5.9 | 8.3 | 2.1 | 6.2 | |||||||||||||||||||||||||||||
Total adjustments | $ | 28.2 | 2.7 | 25.5 | $ | 32.5 | 3.6 | 28.9 | |||||||||||||||||||||||||||
13
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION (EBITDA)
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income attributable to Murphy (GAAP) | $ | 98.3 | 350.6 | $ | 289.9 | 237.2 | |||||||||||||||||
| Income tax expense | 34.9 | 105.1 | 88.7 | 88.1 | |||||||||||||||||||
| Interest expense, net | 29.9 | 41.4 | 58.7 | 78.7 | |||||||||||||||||||
| Depreciation, depletion and amortization expense ¹ | 210.1 | 188.2 | 399.3 | 344.8 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 373.2 | 685.3 | $ | 836.6 | 748.8 | |||||||||||||||||
| Write-off of previously suspended exploration well | 17.1 | — | 17.1 | — | |||||||||||||||||||
| Accretion of asset retirement obligations ¹ | 10.1 | 10.2 | 20.0 | 20.7 | |||||||||||||||||||
| Foreign exchange loss (gain) | 7.9 | (8.0) | 8.3 | (8.0) | |||||||||||||||||||
| Mark-to-market loss on contingent consideration | 3.2 | 31.7 | 7.1 | 129.8 | |||||||||||||||||||
| Discontinued operations loss | 0.6 | 0.9 | 0.3 | 1.5 | |||||||||||||||||||
| Mark-to-market (gain) loss on derivative instruments | — | (88.1) | — | 100.4 | |||||||||||||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 412.1 | 632.0 | $ | 889.4 | 993.2 | |||||||||||||||||
1 Depreciation, depletion, and amortization expense, 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 June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income attributable to Murphy (GAAP) | $ | 98.3 | 350.6 | $ | 289.9 | 237.2 | |||||||||||||||||
| Income tax expense | 34.9 | 105.1 | 88.7 | 88.1 | |||||||||||||||||||
| Interest expense, net | 29.9 | 41.4 | 58.7 | 78.7 | |||||||||||||||||||
| Depreciation, depletion and amortization expense ¹ | 210.1 | 188.2 | 399.3 | 344.8 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | 373.2 | 685.3 | 836.6 | 748.8 | |||||||||||||||||||
Exploration expenses 1 | 89.5 | 15.2 | 99.7 | 62.7 | |||||||||||||||||||
| EBITDAX attributable to Murphy (Non-GAAP) | 462.7 | 700.5 | 936.3 | 811.5 | |||||||||||||||||||
| Accretion of asset retirement obligations ¹ | 10.1 | 10.2 | 20.0 | 20.7 | |||||||||||||||||||
| Foreign exchange loss (gain) | 7.9 | (8.0) | 8.3 | (8.0) | |||||||||||||||||||
| Mark-to-market loss on contingent consideration | 3.2 | 31.7 | 7.1 | 129.8 | |||||||||||||||||||
| Discontinued operations loss | 0.6 | 0.9 | 0.3 | 1.5 | |||||||||||||||||||
| Mark-to-market (gain) loss on derivative instruments | — | (88.1) | — | 100.4 | |||||||||||||||||||
| Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 484.5 | $ | 647.2 | $ | 972.0 | $ | 1,055.9 | |||||||||||||||
1 Depreciation, depletion, and amortization expense, accretion of asset retirement obligations 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 June 30, 2023 | Three Months Ended June 30, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
United States 1 | $ | 696.2 | 168.9 | $ | 978.0 | 491.5 | ||||||||
| Canada | 118.3 | 2.5 | 206.6 | 47.2 | ||||||||||
| Other | — | (32.3) | 13.7 | (3.5) | ||||||||||
| Total exploration and production | 814.5 | 139.1 | 1,198.3 | 535.2 | ||||||||||
| Corporate | 0.1 | (46.6) | (97.2) | (124.8) | ||||||||||
| Continuing operations | 814.6 | 92.5 | 1,101.1 | 410.4 | ||||||||||
| Discontinued operations, net of tax | — | (0.6) | — | (0.9) | ||||||||||
| Total including noncontrolling interest | $ | 814.6 | 91.9 | $ | 1,101.1 | 409.5 | ||||||||
| Net income attributable to Murphy | 98.3 | 350.6 | ||||||||||||
| Six Months Ended June 30, 2023 | Six Months Ended June 30, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
United States 1 | $ | 1,378.5 | 394.9 | $ | 1,685.4 | 744.4 | ||||||||
| Canada | 274.1 | 24.4 | 372.7 | 69.9 | ||||||||||
| Other | 3.6 | (37.6) | 13.7 | (47.7) | ||||||||||
| Total exploration and production | 1,656.2 | 381.7 | 2,071.8 | 766.6 | ||||||||||
| Corporate | 0.1 | (75.2) | (417.8) | (421.1) | ||||||||||
| Continuing operations | 1,656.3 | 306.5 | 1,654.0 | 345.5 | ||||||||||
| Discontinued operations, net of tax | — | (0.3) | — | (1.5) | ||||||||||
| Total including noncontrolling interest | $ | 1,656.3 | 306.2 | $ | 1,654.0 | 344.0 | ||||||||
| Net income attributable to Murphy | 289.9 | 237.2 | ||||||||||||
1 Includes results attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
16
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
THREE MONTHS ENDED JUNE 30, 2023, AND 2022
| (Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Three Months Ended June 30, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 696.2 | 105.3 | — | 801.5 | |||||||||
| Sales of purchased natural gas | — | 13.0 | — | 13.0 | ||||||||||
| Lease operating expenses | 156.5 | 37.5 | 0.1 | 194.1 | ||||||||||
| Severance and ad valorem taxes | 12.4 | 0.4 | — | 12.8 | ||||||||||
| Transportation, gathering and processing | 39.9 | 20.1 | — | 60.0 | ||||||||||
| Costs of purchased natural gas | — | 9.7 | — | 9.7 | ||||||||||
| Depreciation, depletion and amortization | 178.0 | 35.0 | — | 213.0 | ||||||||||
| Accretion of asset retirement obligations | 9.3 | 1.9 | 0.1 | 11.3 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 79.8 | — | 15.8 | 95.6 | ||||||||||
| Geological and geophysical | 0.4 | 0.1 | 10.0 | 10.5 | ||||||||||
| Other exploration | 1.7 | — | 5.3 | 7.0 | ||||||||||
| 81.9 | 0.1 | 31.1 | 113.1 | |||||||||||
| Undeveloped lease amortization | 2.1 | — | 0.6 | 2.7 | ||||||||||
| Total exploration expenses | 84.0 | 0.1 | 31.7 | 115.8 | ||||||||||
| Selling and general expenses | (1.9) | 4.7 | 2.6 | 5.4 | ||||||||||
| Other | 0.5 | 5.4 | 1.4 | 7.3 | ||||||||||
| Results of operations before taxes | 217.5 | 3.5 | (35.9) | 185.1 | ||||||||||
| Income tax provisions (benefits) | 48.6 | 1.0 | (3.6) | 46.0 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 168.9 | 2.5 | (32.3) | 139.1 | |||||||||
| Three Months Ended June 30, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 977.8 | 156.8 | 13.7 | 1,148.3 | |||||||||
| Sales of purchased natural gas | 0.2 | 49.8 | — | 50.0 | ||||||||||
| Lease operating expenses | 109.5 | 36.9 | 0.9 | 147.3 | ||||||||||
| Severance and ad valorem taxes | 17.3 | 0.3 | — | 17.6 | ||||||||||
| Transportation, gathering and processing | 32.3 | 17.6 | — | 49.9 | ||||||||||
| Costs of purchased natural gas | 0.2 | 47.7 | — | 47.9 | ||||||||||
| Depreciation, depletion and amortization | 153.7 | 35.6 | 3.4 | 192.7 | ||||||||||
| Accretion of asset retirement obligations | 9.1 | 2.4 | 0.1 | 11.6 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | (0.7) | — | 2.0 | 1.3 | ||||||||||
| Geological and geophysical | — | 0.1 | 0.8 | 0.9 | ||||||||||
| Other exploration | 2.9 | 0.3 | 6.0 | 9.2 | ||||||||||
| 2.2 | 0.4 | 8.8 | 11.4 | |||||||||||
| Undeveloped lease amortization | 2.3 | — | 1.4 | 3.7 | ||||||||||
| Total exploration expenses | 4.5 | 0.4 | 10.2 | 15.1 | ||||||||||
| Selling and general expenses | 3.2 | 3.8 | 2.1 | 9.1 | ||||||||||
| Other | 35.3 | (2.3) | — | 33.0 | ||||||||||
| Results of operations before taxes | 612.9 | 64.2 | (3.0) | 674.1 | ||||||||||
| Income tax provisions | 121.4 | 17.0 | 0.5 | 138.9 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 491.5 | 47.2 | (3.5) | 535.2 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
17
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
SIX MONTHS ENDED JUNE 30, 2023, AND 2022
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Six Months Ended June 30, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 1,378.5 | 217.2 | 3.6 | 1,599.3 | |||||||||
| Sales of purchased natural gas | — | 56.8 | — | 56.8 | ||||||||||
| Lease operating expenses | 319.2 | 74.3 | 0.7 | 394.2 | ||||||||||
| Severance and ad valorem taxes | 23.5 | 0.7 | — | 24.2 | ||||||||||
| Transportation, gathering and processing | 77.3 | 36.5 | — | 113.8 | ||||||||||
| Costs of purchased natural gas | — | 41.9 | — | 41.9 | ||||||||||
| Depreciation, depletion and amortization | 338.2 | 66.7 | 0.9 | 405.8 | ||||||||||
| Accretion of asset retirement obligations | 18.4 | 3.9 | 0.2 | 22.5 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | 79.6 | — | 16.9 | 96.5 | ||||||||||
| Geological and geophysical | 0.7 | 0.1 | 10.5 | 11.3 | ||||||||||
| Other exploration | 3.3 | 0.1 | 9.4 | 12.8 | ||||||||||
| 83.6 | 0.2 | 36.8 | 120.6 | |||||||||||
| Undeveloped lease amortization | 4.1 | 0.1 | 1.2 | 5.4 | ||||||||||
| Total exploration expenses | 87.7 | 0.3 | 38.0 | 126.0 | ||||||||||
| Selling and general expenses | 4.5 | 7.1 | 2.8 | 14.4 | ||||||||||
| Other | 9.9 | 9.7 | 1.4 | 21.0 | ||||||||||
| Results of operations before taxes | 499.8 | 32.9 | (40.4) | 492.3 | ||||||||||
| Income tax provisions (benefits) | 104.9 | 8.5 | (2.8) | 110.6 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 394.9 | 24.4 | (37.6) | 381.7 | |||||||||
| Six Months Ended June 30, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 1,685.2 | 286.1 | 13.7 | 1,985.0 | |||||||||
| Sales of purchased natural gas | 0.2 | 86.6 | — | 86.8 | ||||||||||
| Lease operating expenses | 209.4 | 73.8 | 0.9 | 284.1 | ||||||||||
| Severance and ad valorem taxes | 31.5 | 0.7 | — | 32.2 | ||||||||||
| Transportation, gathering and processing | 61.5 | 35.3 | — | 96.8 | ||||||||||
| Costs of purchased natural gas | 0.2 | 81.6 | — | 81.8 | ||||||||||
| Depreciation, depletion and amortization | 280.2 | 69.8 | 3.5 | 353.5 | ||||||||||
| Accretion of asset retirement obligations | 18.5 | 4.9 | 0.1 | 23.5 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | (0.7) | — | 34.8 | 34.1 | ||||||||||
| Geological and geophysical | 2.6 | 0.1 | 1.0 | 3.7 | ||||||||||
| Other exploration | 4.4 | 0.4 | 12.1 | 16.9 | ||||||||||
| 6.3 | 0.5 | 47.9 | 54.7 | |||||||||||
| Undeveloped lease amortization | 4.7 | 0.1 | 3.2 | 8.0 | ||||||||||
| Total exploration expenses | 11.0 | 0.6 | 51.1 | 62.7 | ||||||||||
| Selling and general expenses | 11.5 | 8.9 | 4.5 | 24.9 | ||||||||||
| Other | 138.1 | 2.8 | 0.4 | 141.3 | ||||||||||
| Results of operations before taxes | 923.5 | 94.5 | (46.8) | 971.2 | ||||||||||
| Income tax provisions (benefits) | 179.1 | 24.6 | 0.9 | 204.6 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 744.4 | 69.9 | (47.7) | 766.6 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
18
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
(Dollars per barrel of oil equivalents sold) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
United States – Eagle Ford Shale | |||||||||||||||||||||||
Lease operating expense | $ | 11.48 | 11.41 | $ | 13.06 | 11.81 | |||||||||||||||||
Severance and ad valorem taxes | 3.68 | 5.07 | 3.93 | 5.10 | |||||||||||||||||||
Depreciation, depletion and amortization (DD&A) expense | 26.48 | 25.57 | 26.35 | 25.67 | |||||||||||||||||||
United States – Gulf of Mexico1 | |||||||||||||||||||||||
| Lease operating expense | $ | 14.72 | 10.25 | $ | 14.71 | 10.63 | |||||||||||||||||
| Severance and ad valorem taxes | 0.07 | 0.07 | 0.08 | 0.08 | |||||||||||||||||||
DD&A expense | 11.44 | 9.86 | 11.33 | 9.71 | |||||||||||||||||||
Canada – Onshore | |||||||||||||||||||||||
Lease operating expense | $ | 6.01 | 6.82 | $ | 6.38 | 7.14 | |||||||||||||||||
Severance and ad valorem taxes | 0.07 | 0.06 | 0.07 | 0.07 | |||||||||||||||||||
DD&A expense | 5.65 | 6.55 | 5.82 | 6.81 | |||||||||||||||||||
Canada – Offshore | |||||||||||||||||||||||
| Lease operating expense | $ | 10.96 | 11.60 | $ | 12.60 | 13.63 | |||||||||||||||||
DD&A expense | 9.48 | 11.51 | 9.40 | 11.96 | |||||||||||||||||||
| Total E&P continuing operations | |||||||||||||||||||||||
| Lease operating expense | $ | 11.21 | 9.41 | $ | 11.76 | 9.80 | |||||||||||||||||
Severance and ad valorem taxes | 0.74 | 1.12 | 0.72 | 1.11 | |||||||||||||||||||
DD&A expense | 12.44 | 12.51 | 12.27 | 12.41 | |||||||||||||||||||
| Total oil and gas continuing operations – excluding noncontrolling interest | |||||||||||||||||||||||
Lease operating expense | $ | 11.02 | 9.36 | $ | 11.58 | 9.70 | |||||||||||||||||
Severance and ad valorem taxes | 0.76 | 1.18 | 0.75 | 1.17 | |||||||||||||||||||
DD&A expense | 12.53 | 12.64 | 12.36 | 12.56 | |||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
19
MURPHY OIL CORPORATION
CAPITAL EXPENDITURES
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
(Millions of dollars) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
United States1 | $ | 245.5 | 225.4 | $ | 500.2 | 418.2 | |||||||||||||||||
| Canada | 75.4 | 74.0 | 143.5 | 150.9 | |||||||||||||||||||
| Other | 37.8 | 12.5 | 44.7 | 42.3 | |||||||||||||||||||
| Total | 358.7 | 311.9 | 688.4 | 611.4 | |||||||||||||||||||
| Corporate | 3.6 | 5.2 | 9.9 | 10.5 | |||||||||||||||||||
Total capital expenditures - continuing operations2 | 362.3 | 317.1 | 698.3 | 621.9 | |||||||||||||||||||
Charged to exploration expenses3 | |||||||||||||||||||||||
United States1 | 81.9 | 2.2 | 83.6 | 6.3 | |||||||||||||||||||
| Canada | 0.1 | 0.4 | 0.2 | 0.5 | |||||||||||||||||||
| Other | 31.2 | 8.8 | 36.8 | 47.9 | |||||||||||||||||||
| Total charged to exploration expenses - continuing operations | 113.2 | 11.4 | 120.6 | 54.7 | |||||||||||||||||||
| Total capitalized | $ | 249.1 | 305.7 | $ | 577.7 | 567.2 | |||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the three months ended June 30, 2023, total capital expenditures excluding acquisition-related costs (Côte d’Ivoire and Vietnam) of $32.3 million (2022: $46.5 million) and noncontrolling interest (NCI) of $29.9 million (2022: $5.0 million) is $300.1 million (2022: $265.6 million). For the six months ended June 30, 2023, total capital expenditures excluding acquisition-related costs of $32.3 million (2022:$46.5 million) and noncontrolling interest (NCI) of $38.8 million (2022: $8.6 million) is $627.2 million (2022: $566.8 million).
3 For the three-month and six-month-ended June 30, 2023, charges to exploration expense excludes amortization of undeveloped leases of $2.7 million (2022: $3.7 million) and $5.4 million (2022 $8.0 million), respectively. For the three-month and six-months ended June 30, 2023, charges to exploration expense excluding previously suspended exploration costs of $17.1 million (2022: $0) and NCI of $26.3 million (2022: $0) is $69.8 million (2022: $11.4 million) and $77.2 million (2022: $54.7 million), respectively.
20
MURPHY OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited)
| (Thousands of dollars) | June 30, 2023 | December 31, 2022 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 369,355 | 491,963 | ||||||||
| Accounts receivable | 409,989 | 391,152 | |||||||||
| Inventories | 62,450 | 54,513 | |||||||||
| Prepaid expenses | 27,354 | 34,697 | |||||||||
| Total current assets | 869,148 | 972,325 | |||||||||
Property, plant and equipment, at cost | 8,426,045 | 8,228,016 | |||||||||
| Operating lease assets | 867,353 | 946,406 | |||||||||
| Deferred income taxes | 40,678 | 117,889 | |||||||||
| Deferred charges and other assets | 46,306 | 44,316 | |||||||||
| Total assets | $ | 10,249,530 | 10,308,952 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current maturities of long-term debt, finance lease | $ | 705 | 687 | ||||||||
| Accounts payable | 584,107 | 543,786 | |||||||||
| Income taxes payable | 23,539 | 26,544 | |||||||||
| Other taxes payable | 32,091 | 22,819 | |||||||||
| Operating lease liabilities | 258,278 | 220,413 | |||||||||
| Other accrued liabilities | 135,788 | 443,585 | |||||||||
| Total current liabilities | 1,034,508 | 1,257,834 | |||||||||
| Long-term debt, including finance lease obligation | 1,823,521 | 1,822,452 | |||||||||
| Asset retirement obligations | 843,328 | 817,268 | |||||||||
| Deferred credits and other liabilities | 299,089 | 304,948 | |||||||||
| Non-current operating lease liabilities | 624,736 | 742,654 | |||||||||
| Deferred income taxes | 235,665 | 214,903 | |||||||||
| Total liabilities | 4,860,847 | 5,160,059 | |||||||||
| Equity | |||||||||||
Common Stock, par $1.00 | 195,101 | 195,101 | |||||||||
| Capital in excess of par value | 861,951 | 893,578 | |||||||||
| Retained earnings | 6,259,561 | 6,055,498 | |||||||||
| Accumulated other comprehensive loss | (495,783) | (534,686) | |||||||||
| Treasury stock | (1,586,522) | (1,614,717) | |||||||||
| Murphy Shareholders' Equity | 5,234,308 | 4,994,774 | |||||||||
| Noncontrolling interest | 154,375 | 154,119 | |||||||||
| Total equity | 5,388,683 | 5,148,893 | |||||||||
| Total liabilities and equity | $ | 10,249,530 | 10,308,952 | ||||||||
21
MURPHY OIL CORPORATION
PRODUCTION SUMMARY
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
| United States | Onshore | 26,880 | 26,304 | 23,100 | 23,334 | |||||||||||||||||||||
Gulf of Mexico 1 | 72,022 | 63,427 | 73,850 | 59,363 | ||||||||||||||||||||||
| Canada | Onshore | 3,097 | 4,419 | 3,190 | 4,400 | |||||||||||||||||||||
| Offshore | 2,913 | 3,128 | 2,687 | 3,224 | ||||||||||||||||||||||
| Other | 212 | 1,383 | 240 | 833 | ||||||||||||||||||||||
| Total net crude oil and condensate - continuing operations | 105,124 | 98,661 | 103,067 | 91,154 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
| United States | Onshore | 4,328 | 5,178 | 4,243 | 5,006 | |||||||||||||||||||||
Gulf of Mexico 1 | 6,291 | 4,913 | 6,316 | 4,223 | ||||||||||||||||||||||
| Canada | Onshore | 558 | 859 | 691 | 921 | |||||||||||||||||||||
| Total net natural gas liquids - continuing operations | 11,177 | 10,950 | 11,250 | 10,150 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
| United States | Onshore | 24,195 | 29,651 | 24,178 | 28,512 | |||||||||||||||||||||
Gulf of Mexico 1 | 69,904 | 63,703 | 72,539 | 59,902 | ||||||||||||||||||||||
| Canada | Onshore | 352,265 | 288,019 | 328,878 | 273,237 | |||||||||||||||||||||
| Total net natural gas - continuing operations | 446,364 | 381,373 | 425,595 | 361,651 | ||||||||||||||||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 190,695 | 173,173 | 185,250 | 161,579 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,949) | (7,962) | (6,279) | (8,044) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (204) | (319) | (218) | (303) | ||||||||||||||||||||||
Net natural gas – thousands of cubic feet per day 2 | (1,751) | (3,097) | (2,051) | (2,845) | ||||||||||||||||||||||
| Total noncontrolling interest | (6,445) | (8,797) | (6,839) | (8,821) | ||||||||||||||||||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 184,250 | 164,376 | 178,411 | 152,758 | ||||||||||||||||||||||
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 June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | ||||||||||||||||||||||||||
| United States | Onshore | $ | 72.39 | 110.66 | $ | 73.47 | $ | 103.39 | ||||||||||||||||||
Gulf of Mexico 1 | 73.82 | 109.55 | 73.54 | 102.76 | ||||||||||||||||||||||
Canada 2 | Onshore | 68.50 | 100.51 | 71.46 | 96.84 | |||||||||||||||||||||
| Offshore | 80.14 | 115.65 | 79.26 | 113.46 | ||||||||||||||||||||||
| Other | — | 86.51 | 89.05 | 86.51 | ||||||||||||||||||||||
| Natural gas liquids – dollars per barrel | ||||||||||||||||||||||||||
| United States | Onshore | 16.60 | 38.29 | 19.28 | 38.30 | |||||||||||||||||||||
Gulf of Mexico 1 | 20.16 | 40.46 | 22.89 | 41.95 | ||||||||||||||||||||||
Canada 2 | Onshore | 29.90 | 63.99 | 39.82 | 59.23 | |||||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | ||||||||||||||||||||||||||
| United States | Onshore | 1.88 | 7.06 | 2.19 | 5.89 | |||||||||||||||||||||
Gulf of Mexico 1 | 2.33 | 7.52 | 2.81 | 6.43 | ||||||||||||||||||||||
Canada 2 | Onshore | 1.85 | 2.78 | 2.17 | 2.66 | |||||||||||||||||||||
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 AUGUST 1, 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 | 7/1/2023 | 12/31/2023 | ||||||||||||||||||||||||||||||||
| 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 | 7/1/2023 | 10/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 15 | US$1.98 | 11/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
1 Fixed price forward sale contracts are accounted for as normal sales and purchases for accounting purposes.
24
MURPHY OIL CORPORATION
THIRD QUARTER 2023 GUIDANCE
| Oil BOPD | NGLs BOPD | Gas MCFD | Total BOEPD | ||||||||||||||||||||
| Production – net | |||||||||||||||||||||||
| U.S. – Eagle Ford Shale | 27,000 | 4,900 | 27,900 | 36,600 | |||||||||||||||||||
| – Gulf of Mexico excluding NCI | 65,900 | 6,200 | 66,200 | 83,100 | |||||||||||||||||||
| Canada – Tupper Montney | — | — | 380,400 | 63,400 | |||||||||||||||||||
| – Kaybob Duvernay and Placid Montney | 2,900 | 700 | 12,700 | 5,700 | |||||||||||||||||||
| – Offshore | 2,900 | — | — | 2,900 | |||||||||||||||||||
| Other | 300 | — | — | 300 | |||||||||||||||||||
Total net production (BOEPD) - excluding NCI 1 | 188,000 to 196,000 | ||||||||||||||||||||||
| Exploration expense ($ millions) | $32 | ||||||||||||||||||||||
| FULL YEAR 2023 GUIDANCE | |||||||||||||||||||||||
Total net production (BOEPD) - excluding NCI 2 | 180,000 to 186,000 | ||||||||||||||||||||||
Capital expenditures – excluding NCI ($ millions) 3 | $950 to $1,025 | ||||||||||||||||||||||
| ¹ Excludes noncontrolling interest of MP GOM of 5,700 BOPD of oil, 200 BOPD of NGLs, and 2,100 MCFD gas. | |||||||||||||||||||||||
| ² Excludes noncontrolling interest of MP GOM of 6,100 BOPD of oil, 200 BOPD of NGLs, and 2,100 MCFD gas. | |||||||||||||||||||||||
| ³ Excludes noncontrolling interest of MP GOM of $72 million and acquisition-related costs of $45 million. | |||||||||||||||||||||||
25