EXHIBIT 99.1
MURPHY OIL CORPORATION ANNOUNCES FIRST QUARTER 2023 FINANCIAL AND OPERATING RESULTS, REAFFIRMS 2023 PRODUCTION AND CAPITAL EXPENDITURE GUIDANCE RANGES
Exceeded Upper End of Guidance Range With Production of 172.5 MBOEPD,
Announced Discovery at Longclaw #1 Exploration Well in Gulf of Mexico,
Received Credit Rating Upgrade to BB+ from S&P Global
HOUSTON, Texas, May 3, 2023 – Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the first quarter ended March 31, 2023, including net income attributable to Murphy of $192 million, or $1.22 net income per diluted share. Excluding discontinued operations and other items affecting comparability between periods, adjusted net income attributable to Murphy was $195 million, or $1.24 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 first quarter include:
•Exceeded upper end of guidance range with production of 172.5 thousand barrels of oil equivalent per day (MBOEPD), including more than 94 thousand barrels of oil per day (MBOPD)
•Commenced production at Samurai #5 in Green Canyon 432 in the Gulf of Mexico, with eight wells from the Khaleesi, Mormont and Samurai fields now producing at King’s Quay
•Named apparent high bidder on six deepwater blocks in Gulf of Mexico Federal Lease Sale 259
•Brought online 10 operated wells in the Eagle Ford Shale and five operated wells in the Tupper Montney with production meeting company expectations
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Subsequent to the first quarter:
•Celebrated one-year anniversary of achieving first oil at King’s Quay with gross cumulative production exceeding 30 million barrels of oil equivalent (MMBOE)
•Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico
•Initiated drilling the Chinook #7 operated exploration well in Walker Ridge 425 in the Gulf of Mexico
•Maintained quarterly dividend of $0.275 per share or $1.10 per share annualized
•Received a credit rating upgrade to BB+ with a stable outlook from S&P Global
“We are off to a great start for 2023 as we advance our strategy of Delever, Execute, Explore, Return,” said Roger W. Jenkins, President and Chief Executive Officer. “We continued our execution excellence by maintaining strong well performance and uptime across all our assets. Onshore, we began our well delivery program, realizing initial results aligned to our plan. In the Gulf of Mexico, we brought online Samurai #5 following last year’s discovery of additional pay zones in the field, and production is exceeding expectations. Early in the second quarter we celebrated the one-year anniversary of achieving first oil at King’s Quay, where we recently established another record rate of 126 MBOEPD gross production. As we progress our exploration strategy, I’m pleased with the discovery at our Longclaw prospect that was drilled in the second quarter near King’s Quay. This well will support the facility’s long-term production profile. Looking ahead to the remainder of the year, we will continue to progress our capital allocation framework with increasing returns to shareholders and additional debt reduction.”
FIRST QUARTER 2023 RESULTS
The company recorded net income attributable to Murphy of $192 million, or $1.22 net income per diluted share, for the first 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 $195 million, or $1.24 adjusted net income per diluted share for the same period. Adjusted net income includes an after-tax increase for a $3 million non-cash mark-to-market loss on contingent consideration. Details for first 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 $464 million. Earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) attributable to Murphy were $474 million. Adjusted EBITDA attributable
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to Murphy was $478 million. Adjusted EBITDAX attributable to Murphy was $488 million. Reconciliations for first quarter EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX can be found in the attached schedules.
In the first quarter, Murphy paid a total of $172 million in contingent consideration payments related to two Gulf of Mexico acquisitions that closed in 2018 and 2019. Of these remaining revenue-sharing contingent payments, $124 million was associated with improved operational activity and prices and $48 million is reflected in financing activities as originally calculated. The final payment of $25 million, attributable to the one-year anniversary of achieving first oil at King’s Quay, was paid in April.
First quarter production averaged 172.5 MBOEPD and consisted of 55 percent oil volumes, or 94 MBOPD. Production in the quarter exceeded the upper end of the guidance range, primarily driven by ongoing strong well performance from the Khaleesi, Mormont and Samurai fields in the Gulf of Mexico, as well as lower realized royalty rates in the Tupper Montney natural gas asset. Details for first quarter production can be found in the attached schedules.
FINANCIAL POSITION
Murphy had approximately $1.1 billion of liquidity on March 31, 2023, with no borrowings on the $800 million credit facility and $312 million of cash and cash equivalents, inclusive of NCI.
On March 31, 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 7.5 years and a weighted average coupon of 6.2 percent.
Subsequent to quarter end, Murphy received a credit rating upgrade by S&P Global to BB+ with a stable outlook.
“Murphy’s credit rating upgrade is a reflection of our strong operational execution, which has led to enhanced quarterly cash flows and ongoing debt reduction. With the contingent payments related to our successful Gulf of Mexico acquisitions now behind us, our operational momentum underpins our capital allocation framework goals for the year,” stated Jenkins.
OPERATIONS SUMMARY
Onshore
In the first quarter of 2023, the onshore business produced approximately 82 MBOEPD, which included 33 percent liquids volumes.
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Eagle Ford Shale – Production averaged 27 MBOEPD with 70 percent oil volumes and 85 percent liquids volumes. As planned, during the quarter Murphy brought 10 operated Karnes wells online. Additionally, four non-operated Tilden wells and three non-operated Catarina wells were brought online.
Tupper Montney – Natural gas production averaged 292 million cubic feet per day (MMCFD) in the first quarter. Five operated wells were brought online as planned. Production for the quarter exceeded guidance by 27 MMCFD, which included more than 20 MMCFD benefit from a lower realized royalty rate of 10 percent, as well as nearly 7 MMCFD of improved well performance.
Kaybob Duvernay – During the first quarter, production averaged 5 MBOEPD with 72 percent liquids volumes.
Offshore
Excluding NCI, the offshore business produced approximately 90 MBOEPD for the first quarter, which included 80 percent oil.
Gulf of Mexico – Production averaged approximately 87 MBOEPD, consisting of 79 percent oil during the first quarter. These volumes were nearly 4 MBOEPD above guidance, primarily due to stronger well performance. Murphy completed the Samurai #5 well (Green Canyon 432) and commenced production at the end of the quarter with production volumes exceeding company expectations, reflecting ongoing success following last year’s discovery of new pay zones in the field.
Canada – In the first quarter, production averaged 2.5 MBOEPD, consisting of 100 percent oil. The asset life extension project is ongoing for the non-operated Terra Nova floating, production, storage and offloading vessel, which Murphy anticipates will return to production by year-end 2023.
EXPLORATION
Gulf of Mexico – During the first quarter, Murphy, as operator, temporarily suspended drilling the Oso #1 (Atwater Valley 138) exploration well and spud the Longclaw #1 (Green Canyon 433) exploration well. Murphy highlights that this is no indication of potential Oso #1 well results, and the company intends to resume drilling in the third quarter 2023 once the necessary managed pressure drilling equipment and permits have been received. Murphy holds a 33.34 percent working interest (WI) in the Oso well.
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Also during the quarter, Murphy participated in the Gulf of Mexico Federal Lease Sale 259 and was named apparent high bidder on six deepwater blocks.
Subsequent to the first quarter, Murphy drilled a discovery at the Longclaw #1 exploration 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. Murphy as operator holds a 10 percent WI in the well.
The company continued its operated Gulf of Mexico exploration program as it spud the Chinook #7 exploration well in Walker Ridge 425 after quarter end. Murphy holds a 66.66 percent WI in the well, excluding NCI.
“I am pleased with our success in our first exploration well of the year. We look forward to the upcoming results of the Oso and Chinook wells later this year, which are larger opportunities for Murphy,” Jenkins stated.
2023 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Murphy reaffirms its 2023 accrued capital expenditures (CAPEX) plan range of $875 million to $1.025 billion. First quarter accrued CAPEX of $327 million was lower than guidance primarily due to timing revisions for Gulf of Mexico projects. The company also reaffirms its full year 2023 production range of 175.5 to 183.5 MBOEPD, consisting of approximately 55 percent oil and 61 percent liquids volumes.
Production for second quarter 2023 is estimated to be in the range of 173 to 181 MBOEPD with 95 MBOPD, or 54 percent, oil volumes. This range includes planned downtime of 6.7 MBOEPD offshore and 3.0 MBOEPD onshore. Murphy forecasts second quarter accrued CAPEX of $320 million. Both production and CAPEX guidance ranges exclude NCI.
Detailed guidance for the second 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.
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CONFERENCE CALL AND WEBCAST SCHEDULED FOR MAY 3, 2023
Murphy will host a conference call to discuss first quarter 2023 financial and operating results on Wednesday, May 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 04864163.
FINANCIAL DATA
Summary financial data and operating statistics for first 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 second 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.
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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, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, 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
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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.
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
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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 March 31, | |||||||||||
| (Thousands of dollars, except per share amounts) | 2023 | 2022 | |||||||||
| Revenues and other income | |||||||||||
| Revenue from production | $ | 796,231 | 834,528 | ||||||||
| Sales of purchased natural gas | 43,737 | 36,846 | |||||||||
| Total revenue from sales to customers | 839,968 | 871,374 | |||||||||
| Loss on derivative instruments | — | (320,777) | |||||||||
| Gain on sale of assets and other income | 1,748 | 2,364 | |||||||||
| Total revenues and other income | 841,716 | 552,961 | |||||||||
| Costs and expenses | |||||||||||
| Lease operating expenses | 199,984 | 136,825 | |||||||||
| Severance and ad valorem taxes | 11,440 | 14,635 | |||||||||
| Transportation, gathering and processing | 53,922 | 46,923 | |||||||||
| Costs of purchased natural gas | 32,269 | 33,665 | |||||||||
| Exploration expenses, including undeveloped lease amortization | 10,182 | 47,566 | |||||||||
| Selling and general expenses | 18,308 | 33,529 | |||||||||
| Depreciation, depletion and amortization | 195,670 | 164,124 | |||||||||
| Accretion of asset retirement obligations | 11,157 | 11,876 | |||||||||
| Other operating expense | 11,988 | 105,942 | |||||||||
| Total costs and expenses | 544,920 | 595,085 | |||||||||
| Operating income (loss) from continuing operations | 296,796 | (42,124) | |||||||||
| Other income (loss) | |||||||||||
| Other expenses | (73) | (2,495) | |||||||||
| Interest expense, net | (28,855) | (37,277) | |||||||||
| Total other loss | (28,928) | (39,772) | |||||||||
| Income (loss) from continuing operations before income taxes | 267,868 | (81,896) | |||||||||
| Income tax expense (benefit) | 53,833 | (16,961) | |||||||||
| Income (loss) from continuing operations | 214,035 | (64,935) | |||||||||
| Income (loss) from discontinued operations, net of income taxes | 279 | (551) | |||||||||
| Net income (loss) including noncontrolling interest | 214,314 | (65,486) | |||||||||
| Less: Net income attributable to noncontrolling interest | 22,670 | 47,850 | |||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | 191,644 | (113,336) | ||||||||
| INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||
| Continuing operations | $ | 1.23 | (0.73) | ||||||||
| Discontinued operations | — | — | |||||||||
| Net income (loss) | $ | 1.23 | (0.73) | ||||||||
| INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||
| Continuing operations | $ | 1.22 | (0.73) | ||||||||
| Discontinued operations | — | — | |||||||||
| Net income (loss) | $ | 1.22 | (0.73) | ||||||||
| Cash dividends per common share | $ | 0.275 | 0.15 | ||||||||
| Average common shares outstanding (thousands) | |||||||||||
| Basic | 155,857 | 154,916 | |||||||||
| Diluted | 157,389 | 154,916 | |||||||||
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| Three Months Ended March 31, | |||||||||||
| (Thousands of dollars) | 2023 | 2022 | |||||||||
| Operating Activities | |||||||||||
| Net income (loss) including noncontrolling interest | $ | 214,314 | (65,486) | ||||||||
| Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities | |||||||||||
| (Income) loss from discontinued operations | (279) | 551 | |||||||||
| Depreciation, depletion and amortization | 195,670 | 164,124 | |||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | 851 | 32,831 | |||||||||
| Amortization of undeveloped leases | 2,653 | 4,198 | |||||||||
| Accretion of asset retirement obligations | 11,157 | 11,876 | |||||||||
| Deferred income tax expense (benefit) | 49,042 | (20,253) | |||||||||
| Contingent consideration payment | (123,965) | — | |||||||||
| Mark-to-market loss on contingent consideration | 3,938 | 98,126 | |||||||||
| Mark-to-market loss on derivative instruments | — | 188,509 | |||||||||
| Long-term non-cash compensation | 8,536 | 17,288 | |||||||||
| Net increase in non-cash working capital | (75,031) | (80,922) | |||||||||
| Other operating activities, net | (7,110) | (12,512) | |||||||||
| Net cash provided by continuing operations activities | 279,776 | 338,330 | |||||||||
| Investing Activities | |||||||||||
| Property additions and dry hole costs | (345,319) | (244,908) | |||||||||
| Net cash required by investing activities | (345,319) | (244,908) | |||||||||
| Financing Activities | |||||||||||
| Borrowings on revolving credit facility | 100,000 | — | |||||||||
| Repayment of revolving credit facility | (100,000) | — | |||||||||
| Distributions to noncontrolling interest | (9,679) | (39,884) | |||||||||
| Contingent consideration payment | (47,678) | (55,169) | |||||||||
| Issue costs of debt facility | (17) | — | |||||||||
| Cash dividends paid | (42,925) | (23,300) | |||||||||
| Withholding tax on stock-based incentive awards | (14,217) | (15,421) | |||||||||
| Capital lease obligation payments | (139) | (158) | |||||||||
| Net cash required by financing activities | (114,655) | (133,932) | |||||||||
| Effect of exchange rate changes on cash and cash equivalents | 618 | (87) | |||||||||
| Net decrease in cash and cash equivalents | (179,580) | (40,597) | |||||||||
| Cash and cash equivalents at beginning of period | 491,963 | 521,184 | |||||||||
| Cash and cash equivalents at end of period | $ | 312,383 | 480,587 | ||||||||
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MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED NET INCOME (LOSS) (unaudited)
| Three Months Ended March 31, | |||||||||||
(Millions of dollars, except per share amounts) | 2023 | 2022 | |||||||||
| Net income (loss) attributable to Murphy (GAAP) | $ | 191.6 | (113.3) | ||||||||
| Discontinued operations (income) loss | (0.3) | 0.6 | |||||||||
| Net income (loss) from continuing operations attributable to Murphy | 191.3 | (112.7) | |||||||||
Adjustments1: | |||||||||||
| Mark-to-market loss on contingent consideration | 3.9 | 98.1 | |||||||||
| Foreign exchange loss | 0.4 | — | |||||||||
| Mark-to-market loss on derivative instruments | — | 188.5 | |||||||||
| Total adjustments, before taxes | 4.3 | 286.6 | |||||||||
| Income tax expense related to adjustments | 0.9 | 60.6 | |||||||||
| Total adjustments after taxes | 3.4 | 226.0 | |||||||||
| Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 194.7 | 113.3 | ||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 1.24 | 0.73 | ||||||||
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 (loss) 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 (loss) 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 March 31, 2023 | |||||||||||||||||
| (Millions of dollars) | Pretax | Tax | Net | ||||||||||||||
Exploration & Production: | |||||||||||||||||
| United States | $ | 3.9 | (0.8) | 3.1 | |||||||||||||
| Corporate | 0.4 | (0.1) | 0.3 | ||||||||||||||
Total adjustments | $ | 4.3 | (0.9) | 3.4 | |||||||||||||
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MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION (EBITDA)
(unaudited)
| Three Months Ended March 31, | |||||||||||
(Millions of dollars, except per barrel of oil equivalents sold) | 2023 | 2022 | |||||||||
| Net income (loss) attributable to Murphy (GAAP) | $ | 191.6 | (113.3) | ||||||||
| Income tax expense (benefit) | 53.8 | (17.0) | |||||||||
| Interest expense, net | 28.9 | 37.3 | |||||||||
| Depreciation, depletion and amortization expense ¹ | 189.3 | 156.6 | |||||||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 463.6 | 63.6 | ||||||||
| Accretion of asset retirement obligations ¹ | 9.9 | 10.5 | |||||||||
| Mark-to-market loss on contingent consideration | 3.9 | 98.1 | |||||||||
| Foreign exchange loss | 0.4 | — | |||||||||
| Mark-to-market loss on derivative instruments | — | 188.5 | |||||||||
| Discontinued operations (income) loss | (0.3) | 0.6 | |||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 477.5 | 361.3 | ||||||||
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 15,541 | 12,565 | |||||||||
| Net income (loss) attributable to Murphy per barrel of oil equivalents sold | $ | 12.33 | (9.02) | ||||||||
| Adjusted EBITDA per barrel of oil equivalents sold (Non-GAAP) | $ | 30.72 | 28.75 | ||||||||
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 (loss) 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 (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.
Presented above is adjusted EBITDA per barrel of oil equivalent sold. Management believes adjusted EBITDA per barrel of oil equivalent sold is important information because it is used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. Adjusted EBITDA per barrel of oil equivalent sold is a non-GAAP financial metric.
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MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION AND EXPLORATION (EBITDAX)
(unaudited)
| Three Months Ended March 31, | |||||||||||
(Millions of dollars, except per barrel of oil equivalents sold) | 2023 | 2022 | |||||||||
| Net income (loss) attributable to Murphy (GAAP) | $ | 191.6 | (113.3) | ||||||||
| Income tax expense (benefit) | 53.8 | (17.0) | |||||||||
| Interest expense, net | 28.9 | 37.3 | |||||||||
| Depreciation, depletion and amortization expense ¹ | 189.3 | 156.6 | |||||||||
| EBITDA attributable to Murphy (Non-GAAP) | 463.6 | 63.6 | |||||||||
| Exploration expenses | 10.2 | 47.6 | |||||||||
| EBITDAX attributable to Murphy (Non-GAAP) | 473.8 | 111.2 | |||||||||
| Accretion of asset retirement obligations ¹ | 9.9 | 10.5 | |||||||||
| Mark-to-market loss on contingent consideration | 3.9 | 98.1 | |||||||||
| Foreign exchange loss | 0.4 | — | |||||||||
| Discontinued operations (income) loss | (0.3) | 0.6 | |||||||||
| Mark-to-market loss on derivative instruments | — | 188.5 | |||||||||
| Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 487.7 | $ | 408.9 | |||||||
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 15,541 | 12,565 | |||||||||
| Net income (loss) attributable to Murphy per barrel of oil equivalents sold | $ | 12.33 | (9.02) | ||||||||
| Adjusted EBITDAX per barrel of oil equivalents sold (Non-GAAP) | $ | 31.38 | 32.54 | ||||||||
1 Depreciation, depletion, and amortization expense, and accretion of asset retirement obligations 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 (loss) 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 (loss) or Cash provided by operating activities as determined in accordance with accounting principles generally accepted in the United States of America.
Presented above is adjusted EBITDAX per barrel of oil equivalent sold. Management believes adjusted EBITDAX per barrel of oil equivalent sold is important information because it is used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. Adjusted EBITDAX per barrel of oil equivalent sold is a non-GAAP financial metric.
14
MURPHY OIL CORPORATION
FUNCTIONAL RESULTS OF OPERATIONS (unaudited)
| Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | |||||||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | ||||||||||
| Exploration and production | ||||||||||||||
| United States ¹ | $ | 682.3 | 226.0 | 707.4 | 252.9 | |||||||||
| Canada | 155.8 | 21.9 | 166.1 | 22.7 | ||||||||||
| Other | 3.6 | (5.2) | — | (44.2) | ||||||||||
| Total exploration and production | 841.7 | 242.7 | 873.5 | 231.4 | ||||||||||
| Corporate | — | (28.7) | (320.5) | (296.3) | ||||||||||
| Continuing operations | 841.7 | 214.0 | 553.0 | (64.9) | ||||||||||
| Discontinued operations, net of tax | — | 0.3 | — | (0.6) | ||||||||||
| Total including noncontrolling interest | $ | 841.7 | 214.3 | 553.0 | (65.5) | |||||||||
| Net income (loss) attributable to Murphy | 191.6 | (113.3) | ||||||||||||
1 Includes results attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
15
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
THREE MONTHS ENDED MARCH 31, 2023, AND 2022
(Millions of dollars) | United States 1 | Canada | Other | Total | ||||||||||
| Three Months Ended March 31, 2023 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 682.3 | 112.1 | 3.6 | 798.0 | |||||||||
| Sales of purchased natural gas | — | 43.7 | — | 43.7 | ||||||||||
| Lease operating expenses | 162.6 | 36.8 | 0.6 | 200.0 | ||||||||||
| Severance and ad valorem taxes | 11.1 | 0.3 | — | 11.4 | ||||||||||
| Transportation, gathering and processing | 37.4 | 16.5 | — | 53.9 | ||||||||||
| Costs of purchased natural gas | — | 32.3 | — | 32.3 | ||||||||||
| Depreciation, depletion and amortization | 160.3 | 31.6 | 0.9 | 192.8 | ||||||||||
| Accretion of asset retirement obligations | 9.1 | 1.9 | 0.1 | 11.1 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | (0.2) | — | 1.1 | 0.9 | ||||||||||
| Geological and geophysical | 0.3 | — | 0.5 | 0.8 | ||||||||||
| Other exploration | 1.6 | 0.1 | 4.2 | 5.9 | ||||||||||
| 1.7 | 0.1 | 5.8 | 7.6 | |||||||||||
| Undeveloped lease amortization | 2.0 | 0.1 | 0.6 | 2.7 | ||||||||||
| Total exploration expenses | 3.7 | 0.2 | 6.4 | 10.3 | ||||||||||
| Selling and general expenses | 6.4 | 2.3 | 0.2 | 8.9 | ||||||||||
| Other | 9.4 | 4.4 | (0.2) | 13.6 | ||||||||||
| Results of operations before taxes | 282.3 | 29.5 | (4.4) | 307.4 | ||||||||||
| Income tax provisions | 56.3 | 7.6 | 0.8 | 64.7 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 226.0 | 21.9 | (5.2) | 242.7 | |||||||||
| Three Months Ended March 31, 2022 | ||||||||||||||
| Oil and gas sales and other operating revenues | $ | 707.4 | 129.3 | — | 836.7 | |||||||||
| Sales of purchased natural gas | — | 36.8 | — | 36.8 | ||||||||||
| Lease operating expenses | 99.9 | 36.9 | — | 136.8 | ||||||||||
| Severance and ad valorem taxes | 14.2 | 0.4 | — | 14.6 | ||||||||||
| Transportation, gathering and processing | 29.2 | 17.7 | — | 46.9 | ||||||||||
| Costs of purchased natural gas | — | 33.7 | — | 33.7 | ||||||||||
| Depreciation, depletion and amortization | 126.5 | 34.2 | 0.1 | 160.8 | ||||||||||
| Accretion of asset retirement obligations | 9.4 | 2.5 | — | 11.9 | ||||||||||
| Exploration expenses | ||||||||||||||
| Dry holes and previously suspended exploration costs | — | — | 32.8 | 32.8 | ||||||||||
| Geological and geophysical | 2.6 | — | 0.2 | 2.8 | ||||||||||
| Other exploration | 1.5 | 0.1 | 6.1 | 7.7 | ||||||||||
| 4.1 | 0.1 | 39.1 | 43.3 | |||||||||||
| Undeveloped lease amortization | 2.4 | 0.1 | 1.8 | 4.3 | ||||||||||
| Total exploration expenses | 6.5 | 0.2 | 40.9 | 47.6 | ||||||||||
| Selling and general expenses | 8.3 | 5.1 | 2.4 | 15.8 | ||||||||||
| Other | 102.8 | 5.1 | 0.4 | 108.3 | ||||||||||
| Results of operations before taxes | 310.6 | 30.3 | (43.8) | 297.1 | ||||||||||
| Income tax provisions (benefits) | 57.7 | 7.6 | 0.4 | 65.7 | ||||||||||
| Results of operations (excluding Corporate segment) | $ | 252.9 | 22.7 | (44.2) | 231.4 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
16
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES
(unaudited)
| Three Months Ended March 31, | |||||||||||
(Dollars per barrel of oil equivalents sold) | 2023 | 2022 | |||||||||
United States – Eagle Ford Shale | |||||||||||
Lease operating expense | $ | 15.12 | 12.31 | ||||||||
Severance and ad valorem taxes | 4.24 | 5.14 | |||||||||
Depreciation, depletion and amortization (DD&A) expense | 26.18 | 25.79 | |||||||||
United States – Gulf of Mexico1 | |||||||||||
| Lease operating expense | $ | 14.69 | 11.07 | ||||||||
| Severance and ad valorem taxes | 0.08 | 0.09 | |||||||||
DD&A expense | 11.22 | 9.53 | |||||||||
Canada – Onshore | |||||||||||
Lease operating expense | $ | 6.81 | 7.50 | ||||||||
Severance and ad valorem taxes | 0.06 | 0.09 | |||||||||
DD&A expense | 6.01 | 7.10 | |||||||||
Canada – Offshore | |||||||||||
| Lease operating expense | $ | 15.06 | 16.21 | ||||||||
DD&A expense | 9.29 | 12.54 | |||||||||
| Total E&P continuing operations | |||||||||||
| Lease operating expense | $ | 12.35 | 10.25 | ||||||||
Severance and ad valorem taxes | 0.71 | 1.10 | |||||||||
DD&A expense | 12.08 | 12.29 | |||||||||
| Total oil and gas continuing operations – excluding noncontrolling interest | |||||||||||
Lease operating expense | $ | 12.19 | 10.11 | ||||||||
Severance and ad valorem taxes | 0.73 | 1.16 | |||||||||
DD&A expense | 12.18 | 12.46 | |||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
17
MURPHY OIL CORPORATION
CAPITAL EXPENDITURES
(unaudited)
| Three Months Ended March 31, | |||||||||||
(Millions of dollars) | 2023 | 2022 | |||||||||
| Exploration and production | |||||||||||
United States1 | $ | 254.7 | 192.8 | ||||||||
| Canada | 68.1 | 76.8 | |||||||||
| Other | 6.9 | 29.8 | |||||||||
| Total | 329.7 | 299.4 | |||||||||
| Corporate | 6.3 | 5.3 | |||||||||
Total capital expenditures - continuing operations2 | 336.0 | 304.7 | |||||||||
Charged to exploration expenses3 | |||||||||||
United States1 | 1.7 | 4.1 | |||||||||
| Canada | 0.1 | 0.1 | |||||||||
| Other | 5.8 | 39.1 | |||||||||
| Total charged to exploration expenses - continuing operations | 7.6 | 43.3 | |||||||||
| Total capitalized | $ | 328.4 | 261.4 | ||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
2 For the three months ended March 31, 2023, total capital expenditures excluding noncontrolling interest (NCI) of $8.9 million (2022: $3.6 million) are $327.1 million (2022: $301.1 million).
3 For the three months ended March 31, 2023, charges to exploration expense excludes amortization of undeveloped leases of $2.7 million (2022: $4.3 million).
18
MURPHY OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited)
| (Millions of dollars) | March 31, 2023 | December 31, 2022 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 312.4 | 492.0 | ||||||||
| Accounts receivable | 394.9 | 391.2 | |||||||||
| Inventories | 63.5 | 54.5 | |||||||||
| Prepaid expenses | 31.0 | 34.7 | |||||||||
| Total current assets | 801.8 | 972.3 | |||||||||
Property, plant and equipment, at cost | 8,363.0 | 8,228.0 | |||||||||
| Operating lease assets | 903.1 | 946.4 | |||||||||
| Deferred income taxes | 74.1 | 117.9 | |||||||||
| Deferred charges and other assets | 46.5 | 44.3 | |||||||||
| Total assets | $ | 10,188.5 | 10,309.0 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current maturities of long-term debt, finance lease | $ | 0.7 | 0.7 | ||||||||
| Accounts payable | 516.9 | 543.8 | |||||||||
| Income taxes payable | 24.8 | 26.5 | |||||||||
| Other taxes payable | 28.2 | 22.8 | |||||||||
| Operating lease liabilities | 239.4 | 220.4 | |||||||||
| Other accrued liabilities | 218.1 | 443.6 | |||||||||
| Total current liabilities | 1,028.0 | 1,257.8 | |||||||||
| Long-term debt, including finance lease obligation | 1,823.0 | 1,822.5 | |||||||||
| Asset retirement obligations | 830.4 | 817.3 | |||||||||
| Deferred credits and other liabilities | 301.7 | 304.9 | |||||||||
| Non-current operating lease liabilities | 679.9 | 742.7 | |||||||||
| Deferred income taxes | 220.9 | 214.9 | |||||||||
| Total liabilities | 4,883.9 | 5,160.1 | |||||||||
| Equity | |||||||||||
Common Stock, par $1.00 | 195.1 | 195.1 | |||||||||
| Capital in excess of par value | 857.0 | 893.6 | |||||||||
| Retained earnings | 6,204.2 | 6,055.5 | |||||||||
| Accumulated other comprehensive loss | (529.9) | (534.7) | |||||||||
| Treasury stock | (1,588.8) | (1,614.7) | |||||||||
| Murphy Shareholders' Equity | 5,137.6 | 4,994.8 | |||||||||
| Noncontrolling interest | 167.1 | 154.1 | |||||||||
| Total equity | 5,304.7 | 5,148.9 | |||||||||
| Total liabilities and equity | $ | 10,188.5 | 10,309.0 | ||||||||
19
MURPHY OIL CORPORATION
PRODUCTION SUMMARY
(unaudited)
| Three Months Ended March 31, | ||||||||||||||
| (Barrels per day unless otherwise noted) | 2023 | 2022 | ||||||||||||
| Net crude oil and condensate | ||||||||||||||
| United States | Onshore | 19,277 | 20,330 | |||||||||||
Gulf of Mexico 1 | 75,699 | 55,253 | ||||||||||||
| Canada | Onshore | 3,283 | 4,380 | |||||||||||
| Offshore | 2,459 | 3,321 | ||||||||||||
| Other | 269 | 276 | ||||||||||||
| Total net crude oil and condensate - continuing operations | 100,987 | 83,560 | ||||||||||||
| Net natural gas liquids | ||||||||||||||
| United States | Onshore | 4,157 | 4,833 | |||||||||||
Gulf of Mexico 1 | 6,342 | 3,526 | ||||||||||||
| Canada | Onshore | 826 | 983 | |||||||||||
| Total net natural gas liquids - continuing operations | 11,325 | 9,342 | ||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||
| United States | Onshore | 24,160 | 27,361 | |||||||||||
Gulf of Mexico 1 | 75,203 | 56,058 | ||||||||||||
| Canada | Onshore | 305,232 | 258,291 | |||||||||||
| Total net natural gas - continuing operations | 404,595 | 341,710 | ||||||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 179,745 | 149,854 | ||||||||||||
| Noncontrolling interest | ||||||||||||||
| Net crude oil and condensate – barrels per day | (6,613) | (8,128) | ||||||||||||
| Net natural gas liquids – barrels per day | (232) | (287) | ||||||||||||
Net natural gas – thousands of cubic feet per day 2 | (2,354) | (2,590) | ||||||||||||
| Total noncontrolling interest | (7,237) | (8,847) | ||||||||||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 172,508 | 141,007 | ||||||||||||
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.
20
MURPHY OIL CORPORATION
WEIGHTED AVERAGE PRICE SUMMARY
(unaudited)
| Three Months Ended March 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| Crude oil and condensate – dollars per barrel | ||||||||||||||
| United States | Onshore | $ | 74.98 | $ | 93.87 | |||||||||
Gulf of Mexico 1 | 73.27 | 95.02 | ||||||||||||
Canada 2 | Onshore | 74.29 | 93.09 | |||||||||||
| Offshore | 77.93 | 110.66 | ||||||||||||
| Other | 89.05 | — | ||||||||||||
| Natural gas liquids – dollars per barrel | ||||||||||||||
| United States | Onshore | 22.11 | 38.32 | |||||||||||
Gulf of Mexico 1 | 25.63 | 44.05 | ||||||||||||
Canada 2 | Onshore | 46.59 | 55.02 | |||||||||||
| Natural gas – dollars per thousand cubic feet | ||||||||||||||
| United States | Onshore | 2.51 | 4.61 | |||||||||||
Gulf of Mexico 1 | 3.27 | 5.19 | ||||||||||||
Canada 2 | Onshore | 2.55 | 2.52 | |||||||||||
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
21
MURPHY OIL CORPORATION
FIXED PRICE FORWARD SALES AND COMMODITY HEDGE POSITIONS (unaudited)
AS OF MAY 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 | 4/1/2023 | 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 | 4/1/2023 | 10/31/2024 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 15 | US$1.98 | 11/1/2024 | 12/31/2024 | ||||||||||||||||||||||||||||||||
1 Fixed price forward sale contracts are accounted for as normal sales and purchases for accounting purposes.
22
MURPHY OIL CORPORATION
SECOND QUARTER 2023 GUIDANCE
| Oil BOPD | NGLs BOPD | Gas MCFD | Total BOEPD | ||||||||||||||||||||
| Production – net | |||||||||||||||||||||||
| U.S. – Eagle Ford Shale | 25,000 | 4,300 | 26,700 | 33,800 | |||||||||||||||||||
| – Gulf of Mexico excluding NCI | 63,900 | 5,600 | 69,100 | 81,000 | |||||||||||||||||||
| Canada – Tupper Montney | — | — | 320,000 | 53,300 | |||||||||||||||||||
| – Kaybob Duvernay and Placid Montney | 2,900 | 700 | 12,300 | 5,700 | |||||||||||||||||||
| – Offshore | 2,900 | — | — | 2,900 | |||||||||||||||||||
| Other | 300 | — | — | 300 | |||||||||||||||||||
Total net production (BOEPD) - excluding NCI 1 | 173,000 to 181,000 | ||||||||||||||||||||||
| Exploration expense ($ millions) | $55 | ||||||||||||||||||||||
| FULL YEAR 2023 GUIDANCE | |||||||||||||||||||||||
Total net production (BOEPD) - excluding NCI 2 | 175,500 to 183,500 | ||||||||||||||||||||||
Capital expenditures – excluding NCI ($ millions) 3 | $875 to $1,025 | ||||||||||||||||||||||
| ¹ Excludes noncontrolling interest of MP GOM of 5,900 BOPD of oil, 300 BOPD of NGLs, and 2,200 MCFD gas. | |||||||||||||||||||||||
| ² Excludes noncontrolling interest of MP GOM of 6,500 BOPD of oil, 300 BOPD of NGLs, and 2,500 MCFD gas. | |||||||||||||||||||||||
| ³ Excludes noncontrolling interest of MP GOM of $65 MM. | |||||||||||||||||||||||
23