EPS Forecast
Revenue Forecast
EX-99.1
2
mur-2019q4xex991.htm
EXHIBIT 99.1
MUR-2019.Q4-EX99.1
1 Reclassified to current presentation. 2 Net cash provided by discontinued operations is not part of the cash flow reconciliation.
1 Includes results attributable to a noncontrolling interest in MP GOM.
EXHIBIT 99.1
MURPHY OIL CORPORATION ANNOUNCES FOURTH QUARTER
AND FULL YEAR 2019 RESULTS, 2020 GUIDANCE
Achieved 172% Organic Reserve Replacement
Signed Memorandum of Understanding for King’s Quay Floating Production System
EL DORADO, Arkansas, January 30, 2020 - Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the fourth quarter ended December 31, 2019, including a net loss attributable to Murphy of $72 million, or $0.46 net loss per diluted share. Adjusted net income, which excludes discontinued operations and other one-off items, was $25 million, or $0.16 per diluted share.
As previously announced, Murphy closed the Malaysia asset divestiture in the third quarter for $2.0 billion in cash proceeds. These assets were reported as “discontinued operations” for all periods presented. Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude discontinued operations and noncontrolling interest. 1
Highlights for the fourth quarter include:
• | Generated adjusted EBITDA of $404 million, or $22.94 per barrel of oil equivalent sold |
• | Extended debt maturity profile with the issuance of $550 million of 5.875 percent senior notes due 2027, with proceeds used to repurchase an aggregate $521 million of senior notes due 2022 |
• | Achieved first oil from the Nearly Headless Nick well and completed the Chinook #5 well workover, both located in the Gulf of Mexico |
Highlights for full year 2019 include:
• | Attained 172 percent organic reserve replacement with an average three-year total finding and development cost of $12.95 per barrel of oil equivalent |
• | Transformed Murphy into an oil-weighted, Western Hemisphere focused company by closing two significant transactions with the Malaysia divestiture and Gulf of Mexico acquisition |
• | Increased average daily oil production from continuing operations by 66 percent, with total average daily production rising 41 percent from 2018 levels |
• | Completed the $500 million share repurchase program, resulting in a total share count reduction of 12 percent, or approximately 20.7 million shares, to 152.9 million shares |
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• | Generated $1.5 billion of adjusted EBITDA, or $23.99 per barrel of oil equivalent sold |
• | Drilled successful exploration wells in Vietnam, Gulf of Mexico and offshore Mexico |
• | Increased reserve life to 11.8 years |
Highlight subsequent to year-end 2019:
• | Entered into memorandum of understanding regarding Murphy’s 50 percent ownership in the King’s Quay floating production system |
FOURTH QUARTER 2019 RESULTS
The company recorded a net loss, attributable to Murphy, of $72 million, or $0.46 net loss per diluted share, for the fourth quarter 2019. Adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, was $25 million, or $0.16 per diluted share for the same period. The adjusted income from continuing operations excludes the following primary after-tax items: a $106 million non-cash mark-to-market loss on crude oil derivatives and a $25 million loss on extinguishment of debt. Details for fourth quarter results can be found in the attached schedules.
Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations attributable to Murphy was $404 million, or $22.94 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, tax, depreciation, amortization and exploration expenses (EBITDAX) from continuing operations attributable to Murphy was $424 million, or $24.05 per BOE sold. Details for fourth quarter EBITDA and EBITDAX reconciliations can be found in the attached schedules.
Fourth quarter production averaged 194 thousand barrels of oil equivalent per day (MBOEPD) with 59 percent oil and 67 percent liquids. Production was impacted by total unplanned downtime of 8 MBOEPD for the quarter. Non-operated, unplanned downtime was 1,900 barrels of oil equivalent per day (BOEPD) across various fields in the Gulf of Mexico and 1,000 BOEPD at Terra Nova in offshore Canada.
Operated unplanned downtime of 1,500 BOEPD in the Gulf of Mexico was primarily due to a subsea equipment malfunction at Neidermeyer (Mississippi Canyon 209), causing a five-day impact on the three-well field. One well remains down during equipment repairs, which are expected to be complete by second quarter 2020.
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Operated production variances of 3,600 BOEPD in the Eagle Ford Shale were the result of well workover activity on higher rate wells in Catarina, as well as new East Tilden wells outperforming historical Tilden wells but producing below their corporate forecast for the quarter. The majority of the Catarina workovers were complete by the end of fourth quarter 2019 and are currently producing in line with expectations. Details for fourth quarter production can be found in the attached schedules.
FULL YEAR 2019 RESULTS
The company recorded net income, attributable to Murphy, of $1.1 billion, or $6.98 per diluted share, for the full year 2019. The company reported adjusted income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, of $144 million, or $0.87 per diluted share. Details for full year 2019 results can be found in the attached schedules.
Production for the full year averaged 173 MBOEPD and consisted of 60 percent oil and 67 percent liquids volumes. Details for 2019 production can be found in the attached tables.
“Over the course of 2019, we executed two noteworthy transactions as we continued to strategically transform our asset base. Our new portfolio generated strong net income in 2019, supported by increased oil production and positive differentials to West Texas Intermediate oil pricing. This growth led to additional cash flow generation which, in addition to proceeds from the sale of Malaysia, allowed us to return more than $660 million to shareholders through share repurchases and a competitive dividend,” stated Roger W. Jenkins, President and Chief Executive Officer.
FINANCIAL POSITION
In the fourth quarter, Murphy issued $550 million of 5.875 percent senior notes due 2027. Proceeds were used to redeem approximately $240 million of the 4.0 percent senior notes due 2022 and $281 million of the 3.7 percent notes due 2022.
The company had $2.8 billion of outstanding long-term, fixed-rate notes at the end of fourth quarter 2019. The fixed-rate notes had a weighted average maturity of 7.7 years and a weighted average coupon of 5.8 percent.
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As previously announced, Murphy completed its $500 million share repurchase program. The remaining $94 million under the authorization was used to repurchase 4.3 million shares in the fourth quarter. Over the course of the year, Murphy reduced its outstanding shares by approximately 12 percent, or 20.7 million shares, from 173.6 million shares as of April 30 to 152.9 million shares outstanding at completion of the program on October 4, 2019.
As of December 31, 2019, Murphy had approximately $1.9 billion of liquidity, comprised of a fully undrawn $1.6 billion senior unsecured credit facility and approximately $307 million of cash and cash equivalents.
YEAR-END 2019 PROVED RESERVES
Murphy’s preliminary year-end 2019 proved reserves were 800 million barrels of oil equivalent (MMBOE), consisting of 50 percent oil and 57 percent liquids. Total proved reserves were 2 percent lower than at year-end 2018 as a result of the Malaysia divestiture and 2019 production, which were largely offset by the Gulf of Mexico acquisition, improvements to reserves from revisions and extensions across the business. Excluding Malaysia proved reserves of 129 MMBOE at year-end 2018, Murphy increased its proved reserves by 17 percent in 2019.
The company achieved organic reserve replacement of 172 percent with a three-year total finding and development cost of $12.95 per BOE.
2019 Proved Reserves - Preliminary * | |||||
Category | Net Oil (MMBBL) | Net NGLs (MMBBL) | Net Gas (BCF) | Net Equiv. (MMBOE) | |
Proved Developed (PD) | 213 | 27 | 1,272 | 452 | |
Proved Undeveloped (PUD) | 189 | 28 | 788 | 348 | |
Total Proved | 402 | 55 | 2,060 | 800 | |
* Reserves are based on preliminary SEC year-end 2019 audited proved reserves and exclude noncontrolling interest | |||||
“With the transition out of Malaysia, increasing our Gulf of Mexico business, and continued investment in our onshore businesses, we have been able to maintain a sizeable asset base - all while maintaining our liquids weighting at 57 percent. I am also pleased with an increase in our proved developed reserves to 57 percent from 50 percent and our competitive three-year total finding and developing cost metric of $12.95 per BOE,” stated Jenkins.
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SUBSEQUENT TO YEAR-END
Murphy has entered into a memorandum of understanding (MOU) with ArcLight Capital Partners, LLC (ArcLight), a Boston-based energy infrastructure investment manager, regarding Murphy’s 50 percent interest in the King’s Quay floating production system (King’s Quay FPS) in the Gulf of Mexico.
Under the terms of the MOU, Murphy and an affiliate of ArcLight will negotiate definitive agreements detailing the assumption of certain future capital requirements with respect to the King’s Quay FPS and associated export pipelines construction, ownership and operation, as well as the reimbursement of Murphy’s previous capital outlay, including approximately $125 million spent in 2019. The remaining 50 percent of the King’s Quay FPS will continue to be owned by Ridgewood King’s Quay, LLC and ILX Prospect King’s Quay, LLC, both of which are managed by Ridgewood Energy Corporation.
The King’s Quay FPS is scheduled to go into service in mid-2022, with Murphy serving as operator. Designed to process up to 80 thousand barrels of oil per day and up to 100 million cubic feet of natural gas per day from the Khaleesi / Mormont and Samurai fields, the facility will be located in Green Canyon Block 433.
Closing of the transaction is anticipated in late first to early second quarter 2020, with funds received to be held for general corporate purposes.
REGIONAL OPERATIONS SUMMARY
North American Onshore
The North American onshore business produced approximately 104 MBOEPD in the fourth quarter.
Eagle Ford Shale - During the quarter, production averaged 50 MBOEPD with 77 percent oil volumes. The company brought online 10 Catarina wells and eight Tilden wells early in the quarter.
Tupper Montney - Natural gas production averaged 260 million cubic feet per day (MMCFPD) for the quarter. No rig activity occurred during the fourth quarter.
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Kaybob Duvernay - Fourth quarter production averaged 9 MBOEPD. Eight wells were drilled in the quarter for lease retention purposes.
Global Offshore
The offshore business produced 89 MBOEPD for the fourth quarter, comprised of 79 percent oil. This excludes production from discontinued operations and noncontrolling interest. Gulf of Mexico production in the quarter averaged 82 MBOEPD, consisting of 77 percent oil. Canada offshore production averaged 7 MBOEPD, comprised of 100 percent oil.
Gulf of Mexico - The Nearly Headless Nick well (Mississippi Canyon 387) came online during the quarter with a peak rate of approximately 6,900 BOEPD. The Chinook #5 well (Walker Ridge 425) workover was completed late in the quarter with a peak rate of nearly 13,000 BOEPD. As previously disclosed, the Medusa A6 well (Mississippi Canyon 582) recompletion was concluded in the third quarter, with the well coming online early in the fourth quarter at a peak rate of more than 1,600 BOEPD.
The three-well rig campaign at Front Runner (Green Canyon 338 and 339) launched during the quarter, with drilling and completions planned through 2020. The first well was successfully drilled and will be placed online in the first quarter 2020. Additionally, the Khaleesi / Mormont and Samurai field development projects continued to progress, with subsea engineering and construction contracts recently awarded.
Southeast Asia - Brunei production was approximately 570 BOEPD for the quarter. These assets are classified as “held for sale” for financial reporting purposes.
EXPLORATION
Mexico Exploration - Ophir divested its 33 percent working interest in Block 5 equally among the remaining partners, with a net cost to Murphy of $17 million. Murphy now owns 40 percent working interest as operator, with Petronas and Wintershall Dea at 30 percent each.
Vietnam Exploration - In the fourth quarter, Murphy executed the production sharing contract for Block 15-2/17, which is adjacent to Block 15-1/05 and the Lac Da Vang Field. Murphy as operator owns a 40 percent working interest in the block, with PetroVietnam Exploration Production Corporation at 35 percent and SK Innovation Co. Ltd. holding the remaining 25 percent.
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2020 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Murphy is planning 2020 capital expenditures (CAPEX) to be in the range of $1.4 to $1.5 billion with full year 2020 production to be in the range of 190 to 202 MBOEPD. Production for first quarter 2020 is estimated to be in the range of 181 to 193 MBOEPD, impacted by approximately 3 MBOEPD due to Terra Nova being offline. Both production and CAPEX guidance ranges exclude Gulf of Mexico noncontrolling interest (NCI). Murphy’s 2020 plan reflects management’s continued focus on spending within cash flows, generating excess funds such that the company returns cash to shareholders through the longstanding dividend.
The table below illustrates the capital allocation by area.
2020 Capital Expenditure Guidance | |
Area | Percent of Total CAPEX |
US Onshore | 47 |
Gulf of Mexico | 30 |
Canada Onshore | 12 |
Exploration | 7 |
Canada Offshore | 3 |
Other | 1 |
For 2020, Murphy plans to spend $680 million in the Eagle Ford Shale, representing a 13 percent increase from 2019. This capital includes $515 million for drilling 91 and bringing online 97 operated wells, primarily in the company’s Karnes and Catarina acreage, as well as drilling 46 and bringing online 59 non-operated wells during the year in Karnes and Tilden. Murphy’s Eagle Ford Shale budget also includes $165 million for field development.
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The company has also allocated $175 million to its Canada onshore business in the Kaybob Duvernay, Tupper Montney and Placid Montney, which is 38 percent lower than in 2019. Approximately $125 million is allocated to the Kaybob Duvernay, primarily for lease retention to bring online 16 operated wells, with $35 million allocated to the Tupper Montney to bring online five operated wells and $15 million allocated to Placid Montney to bring online 11 non-operated wells.
2020 Onshore Wells Online | ||||||
1Q 2020 | 2Q 2020 | 3Q 2020 | 4Q 2020 | 2020 Total | ||
Eagle Ford Shale | 14 | 28 | 37 | 18 | 97 | |
Kaybob Duvernay | 13 | 1 | 2 | 0 | 16 | |
Tupper Montney | 0 | 5 | 0 | 0 | 5 | |
Non-Op Eagle Ford Shale | 0 | 15 | 1 | 43 | 59 | |
Non-Op Placid Montney | 4 | 7 | 0 | 0 | 11 | |
Note: Non-operated wells are shown gross. Eagle Ford Shale non-operated working interest averages 24 percent. | ||||||
North American onshore production for 2020 is forecast to increase to approximately 105 MBOEPD. Annual average production in the Eagle Ford Shale is expected to grow to 50 MBOEPD, while the Kaybob Duvernay is planned to remain flat at 10 MBOEPD. Tupper Montney production is forecast at approximately 43 MBOEPD.
Murphy has allocated approximately $480 million, or 33 percent, of capital to its offshore assets, with 30 percent planned for the Gulf of Mexico and the remaining 3 percent for Canada offshore. Gulf of Mexico capital will be used for both development drilling and field development projects, including the three-well rig program at Front Runner, activities related to the Khaleesi / Mormont and Samurai developments, St. Malo waterflood, planned well workovers and various non-operated projects. The Cascade #4 well (Walker Ridge 250) workover is scheduled to be complete and placed online in the first half of 2020, as well as the Dalmatian 134 #2 well (Desoto Canyon 134). Canada offshore spending is budgeted for development drilling.
The company forecasts total 2020 offshore production volumes to average 91 MBOEPD, with Gulf of Mexico production of 86 MBOEPD. Canada offshore production is forecast at 4 MBOEPD with the assumption that non-operated Terra Nova remains offline throughout the year for drydock repairs and safety equipment updates, impacting Murphy by approximately 2 MBOEPD in 2020.
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Approximately $100 million is allocated to a four-well exploration program in 2020, with 40 percent for drilling, 15 percent for geological and geophysical studies, and the remainder for lease amortization and other exploration costs. Other capital of approximately $20 million, or 1 percent of budget, supports corporate activities.
“Murphy has again established a capital budget that is focused on spending within free cash flow and covering our longstanding quarterly dividend. We are strategically allocating capital to high returning, oil-weighted projects in the Gulf of Mexico and Eagle Ford Shale that in turn drive a stronger production foundation for long-term cash flow generation,” stated Jenkins.
Detailed guidance for the first quarter and full year 2020 is contained in the following schedule.
CONFERENCE CALL AND WEBCAST SCHEDULED FOR JANUARY 30, 2020
Murphy will host a conference call to discuss fourth quarter 2019 financial and operating results on Thursday, January 30, 2020, at 9:00 a.m. ET. 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 80514484.
FINANCIAL DATA
Summary financial data and operating statistics for fourth quarter 2019, 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 and EBITDAX between periods, as well as guidance for the first quarter and full year 2020, are also included.
1With the close of the previously announced Gulf of Mexico transaction in the fourth quarter 2018, and in 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 will 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, will exclude the NCI, thereby representing only the amounts attributable to Murphy.
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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. It 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 or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: 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; natural hazards impacting our operations; 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 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
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http://ir.murphyoilcorp.com. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
NON-GAAP FINANCIAL MEASURES
This news release contains certain non-GAAP financial measures that management believes are useful tools for internal use and the investment community in evaluating Murphy Oil Corporation’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry. Not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with GAAP and should therefore be considered only as supplemental to such GAAP financial measures. Please see the attached schedules for reconciliations of the differences between the non-GAAP financial measures used in this news release and the most directly comparable GAAP financial measures.
RESERVE REPORTING TO THE SECURITIES EXCHANGE COMMISSION
The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use certain terms in this news release, such as “resource”, “gross resource”, “recoverable resource”, “net risked PMEAN resource”, “recoverable oil”, “resource base”, “EUR” or “estimated ultimate recovery” and similar terms that the SEC’s rules prohibit us from including in filings with the SEC. The SEC permits the optional disclosure of probable and possible reserves; however, we have not disclosed the company’s probable and possible reserves in our filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Annual Report on Form 10-K filed with the SEC and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com.
Investor Contacts:
Kelly Whitley, kelly_whitley@murphyoilcorp.com, 281-675-9107
Bryan Arciero, bryan_arciero@murphyoilcorp.com, 281-675-9339
Megan Larson, megan_larson@murphyoilcorp.com, 281-675-9470
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MURPHY OIL CORPORATION
SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(Thousands of dollars, except per share amounts) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 ¹ | 2019 | 2018 ¹ | |||||||||
Revenues | ||||||||||||
Revenue from sales to customers | $ | 756,984 | 476,074 | 2,817,111 | 1,806,473 | |||||||
(Loss) gain on crude contracts | (122,019 | ) | 27,374 | (856 | ) | (41,975 | ) | |||||
Gain on sale of assets and other income | 2,515 | 190 | 12,798 | 26,903 | ||||||||
Total revenues | 637,480 | 503,638 | 2,829,053 | 1,791,401 | ||||||||
Costs and expenses | ||||||||||||
Lease operating expenses | 188,720 | 100,012 | 605,180 | 353,832 | ||||||||
Severance and ad valorem taxes | 10,987 | 11,973 | 47,959 | 52,072 | ||||||||
Transportation, gathering and processing | 47,567 | 25,216 | 176,315 | 75,043 | ||||||||
Exploration expenses, including undeveloped lease amortization | 19,535 | 32,462 | 95,105 | 101,812 | ||||||||
Selling and general expenses | 56,478 | 40,118 | 232,736 | 205,192 | ||||||||
Depreciation, depletion and amortization | 328,572 | 204,617 | 1,147,842 | 775,614 | ||||||||
Accretion of asset retirement obligations | 10,682 | 7,885 | 40,506 | 27,119 | ||||||||
Impairment of assets | — | 20,000 | — | 20,000 | ||||||||
Other expense (benefit) | 11,675 | 9,903 | 38,117 | (34,870 | ) | |||||||
Total costs and expenses | 674,216 | 452,186 | 2,383,760 | 1,575,814 | ||||||||
Operating income from continuing operations | (36,736 | ) | 51,452 | 445,293 | 215,587 | |||||||
Other income (loss) | ||||||||||||
Interest and other income (loss) | (4,386 | ) | 8,487 | (22,520 | ) | 7,774 | ||||||
Interest expense, net | (74,180 | ) | (47,284 | ) | (219,275 | ) | (180,359 | ) | ||||
Total other loss | (78,566 | ) | (38,797 | ) | (241,795 | ) | (172,585 | ) | ||||
Income (loss) from continuing operations before income taxes | (115,302 | ) | 12,655 | 203,498 | 43,002 | |||||||
Income tax expense (benefit) | (24,036 | ) | (34,956 | ) | 14,683 | (126,136 | ) | |||||
Income (loss) from continuing operations | (91,266 | ) | 47,611 | 188,815 | 169,138 | |||||||
Income from discontinued operations, net of income taxes 2 | 36,855 | 64,160 | 1,064,487 | 250,348 | ||||||||
Net (loss) income including noncontrolling interest | (54,411 | ) | 111,771 | 1,253,302 | 419,486 | |||||||
Less: Net income attributable to noncontrolling interest | 17,313 | 8,392 | 103,570 | 8,392 | ||||||||
NET (LOSS) INCOME ATTRIBUTABLE TO MURPHY | $ | (71,724 | ) | 103,379 | 1,149,732 | 411,094 | ||||||
INCOME (LOSS) PER COMMON SHARE – BASIC | ||||||||||||
Continuing operations | $ | (0.71 | ) | 0.23 | 0.52 | 0.93 | ||||||
Discontinued operations | 0.24 | 0.37 | 6.49 | 1.45 | ||||||||
Net (loss) income | $ | (0.47 | ) | 0.60 | 7.01 | 2.38 | ||||||
INCOME (LOSS) PER COMMON SHARE – DILUTED | ||||||||||||
Continuing operations | $ | (0.70 | ) | 0.22 | 0.52 | 0.92 | ||||||
Discontinued operations | 0.24 | 0.37 | 6.46 | 1.44 | ||||||||
Net (loss) ncome | $ | (0.46 | ) | 0.59 | 6.98 | 2.36 | ||||||
Cash dividends per Common share | 0.25 | 0.25 | 1.00 | 1.00 | ||||||||
Average Common shares outstanding (thousands) | ||||||||||||
Basic | 154,007 | 173,055 | 163,992 | 172,974 | ||||||||
Diluted | 154,915 | 174,312 | 164,812 | 174,209 | ||||||||
1 Reclassified to conform to current presentation.
2 2019 includes gain on sale of Malaysia operations of $985.4 million for the year ended December 31, 2019.
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(Thousands of dollars) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 ¹ | 2019 | 2018 ¹ | |||||||||
Operating Activities | ||||||||||||
Net (loss) income including noncontrolling interest | $ | (54,411 | ) | 111,771 | 1,253,302 | 419,486 | ||||||
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities: | ||||||||||||
Income from discontinued operations | (36,855 | ) | (64,160 | ) | (1,064,487 | ) | (250,348 | ) | ||||
Depreciation, depletion and amortization | 328,572 | 204,617 | 1,147,842 | 775,614 | ||||||||
Previously suspended exploration costs (credits) | (61 | ) | 15,994 | 12,840 | 20,508 | |||||||
Amortization of undeveloped leases | 6,293 | 8,633 | 27,973 | 40,177 | ||||||||
Accretion of asset retirement obligations | 10,682 | 7,885 | 40,506 | 27,119 | ||||||||
Impairment of assets | — | 20,000 | — | 20,000 | ||||||||
Deferred income tax charge (benefit) | (22,067 | ) | (43,234 | ) | 28,530 | (177,627 | ) | |||||
Pretax (gain) loss from sale of assets | 136 | (48 | ) | (227 | ) | (54 | ) | |||||
Mark to market and revaluation of contingent consideration | 8,160 | — | 8,672 | — | ||||||||
Mark to market (gain) loss of crude contracts | 133,440 | (35,019 | ) | 33,364 | (33,954 | ) | ||||||
Long-term non-cash compensation | 16,391 | 19,842 | 76,958 | 72,151 | ||||||||
Net (increase) decrease in noncash operating working capital | (57,144 | ) | (6,602 | ) | (16,887 | ) | (16,103 | ) | ||||
Other operating activities, net | 2,742 | (91,650 | ) | (59,281 | ) | (147,574 | ) | |||||
Net cash provided by continuing operations activities | 335,878 | 148,029 | 1,489,105 | 749,395 | ||||||||
Investing Activities | ||||||||||||
Acquisition of oil and gas properties | 634 | (794,623 | ) | (1,212,315 | ) | (794,623 | ) | |||||
Property additions and dry hole costs | (335,125 | ) | (213,662 | ) | (1,344,271 | ) | (1,011,292 | ) | ||||
Proceeds from sales of property, plant and equipment | 1,310 | 254 | 20,382 | 1,175 | ||||||||
Net cash required by investing activities | (333,181 | ) | (1,008,031 | ) | (2,536,204 | ) | (1,804,740 | ) | ||||
Financing Activities | ||||||||||||
Borrowings on revolving credit facility and term loan | 150,000 | 325,000 | 1,725,000 | 325,000 | ||||||||
Repayment of revolving credit facility and term loan | (150,000 | ) | — | (2,050,000 | ) | — | ||||||
Debt issuance, net of cost | 542,394 | — | 542,394 | — | ||||||||
Early retirement of debt | (521,332 | ) | — | (521,332 | ) | — | ||||||
Loss on early extinguishment of debt | (26,626 | ) | — | (26,626 | ) | — | ||||||
Repurchase of common stock | (93,986 | ) | — | (499,924 | ) | — | ||||||
Capital lease obligation payments | (178 | ) | (164 | ) | (688 | ) | (318 | ) | ||||
Withholding tax on stock-based incentive awards | — | (1,154 | ) | (6,991 | ) | (8,076 | ) | |||||
Distribution to noncontrolling interest | (30,648 | ) | — | (128,158 | ) | — | ||||||
Cash dividends paid | (38,232 | ) | (43,264 | ) | (163,669 | ) | (173,044 | ) | ||||
Net cash (required) provided by financing activities | (168,608 | ) | 280,418 | (1,129,994 | ) | 143,562 | ||||||
Cash Flows from Discontinued Operations 2 | ||||||||||||
Operating activities | (578 | ) | 46,268 | 73,783 | 416,611 | |||||||
Investing activities | 36,832 | 50,563 | 2,022,034 | (10,152 | ) | |||||||
Financing activities | — | (2,419 | ) | (4,914 | ) | (9,432 | ) | |||||
Net cash provided by discontinued operations | 36,254 | 94,412 | 2,090,903 | 397,027 | ||||||||
Cash transferred from discontinued operations to continuing operations | 36,832 | 76,051 | 2,120,397 | 612,543 | ||||||||
Effect of exchange rate changes on cash and cash equivalents | 940 | 15,623 | 3,533 | 28,730 | ||||||||
Net increase (decrease) in cash and cash equivalents | (128,139 | ) | (487,910 | ) | (53,163 | ) | (270,510 | ) | ||||
Cash and cash equivalents at beginning of period | 434,899 | 847,833 | 359,923 | 630,433 | ||||||||
Cash and cash equivalents at end of period | $ | 306,760 | 359,923 | 306,760 | 359,923 | |||||||
13
MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED INCOME (LOSS)
(unaudited)
(Millions of dollars, except per share amounts) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||
Net (loss) income attributable to Murphy (GAAP) | $ | (71.7 | ) | 103.4 | 1,149.7 | 411.1 | ||||||
Discontinued operations (income) loss | (36.9 | ) | (64.1 | ) | (1,064.5 | ) | (250.3 | ) | ||||
(Loss) income from continuing operations | (108.6 | ) | 39.3 | 85.2 | 160.8 | |||||||
Adjustments (after tax): | ||||||||||||
Mark-to-market loss (gain) on crude oil derivative contracts | 105.5 | (27.6 | ) | 26.4 | (26.8 | ) | ||||||
Loss on extinguishment of debt | 25.4 | — | 25.4 | — | ||||||||
Business development transaction costs | — | — | 19.3 | — | ||||||||
Impact of tax reform | (4.2 | ) | (15.7 | ) | (17.2 | ) | (135.7 | ) | ||||
Tax benefits on investments in foreign areas | — | (14.7 | ) | (15.0 | ) | (14.7 | ) | |||||
Write-off of previously suspended exploration wells | — | — | 13.2 | 4.5 | ||||||||
Mark-to-market loss (gain) on contingent consideration | 6.5 | (3.8 | ) | 6.9 | (3.8 | ) | ||||||
Seal insurance proceeds | — | — | (6.2 | ) | (15.2 | ) | ||||||
Foreign exchange losses (gains) | — | (8.8 | ) | 5.9 | (13.6 | ) | ||||||
Ecuador arbitration settlement | — | — | — | (20.5 | ) | |||||||
Impairment of assets | — | 15.8 | — | 15.8 | ||||||||
Brunei working interest income | — | — | — | (16.0 | ) | |||||||
Total adjustments after taxes | 133.2 | (54.8 | ) | 58.7 | (226.0 | ) | ||||||
Adjusted income (loss) from continuing operations attributable to Murphy | $ | 24.6 | (15.5 | ) | 143.9 | (65.2 | ) | |||||
Adjusted income (loss) from continuing operations per average diluted share | $ | 0.16 | (0.09 | ) | 0.87 | (0.37 | ) | |||||
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Adjusted income (loss) from continuing operations attributable to Murphy. Adjusted income (loss) 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 income (loss) 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.
Amounts shown above as reconciling items between Net income and Adjusted income (loss) are presented net of applicable income taxes based on the estimated statutory rate in the applicable tax jurisdiction. The pretax and income tax impacts for adjustments shown above are as follows by area of operations.
(Millions of dollars) | Three Months Ended December 31, 2019 | Year Ended December 31, 2019 | ||||||||||||||||
Pretax | Tax | Net | Pretax | Tax | Net | |||||||||||||
Exploration & Production: | ||||||||||||||||||
United States | $ | 8.2 | (1.7 | ) | 6.5 | 33.0 | (6.9 | ) | 26.1 | |||||||||
Canada | — | (4.2 | ) | (4.2 | ) | (8.0 | ) | (15.4 | ) | (23.4 | ) | |||||||
Other International | — | — | — | 13.2 | (15.0 | ) | (1.8 | ) | ||||||||||
Total E&P | 8.2 | (5.9 | ) | 2.3 | 38.2 | (37.3 | ) | 0.9 | ||||||||||
Corporate: | 165.9 | (35.0 | ) | 130.9 | 72.2 | (14.4 | ) | 57.8 | ||||||||||
Total adjustments | $ | 174.1 | (40.9 | ) | 133.2 | 110.4 | (51.7 | ) | 58.7 | |||||||||
14
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION (EBITDA)
(unaudited)
(Millions of dollars, except per barrel of oil equivalents sold) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||
Net (loss) income attributable to Murphy (GAAP) | $ | (71.7 | ) | 103.4 | 1,149.7 | 411.1 | ||||||
Income tax expense (benefit) | (24.0 | ) | (35.0 | ) | 14.7 | (126.1 | ) | |||||
Interest expense, net | 74.2 | 47.3 | 219.3 | 180.4 | ||||||||
Depreciation, depletion and amortization expense 1 | 310.1 | 199.6 | 1,076.5 | 770.6 | ||||||||
EBITDA attributable to Murphy (Non-GAAP) | $ | 288.6 | 315.3 | 2,460.2 | 1,236.0 | |||||||
Discontinued operations (income) loss | (36.9 | ) | (64.2 | ) | (1,064.5 | ) | (250.3 | ) | ||||
Accretion of asset retirement obligations | 10.7 | 7.9 | 40.5 | 27.1 | ||||||||
Mark-to-market loss (gain) on crude oil derivative contracts | 133.5 | (35.0 | ) | 33.4 | (33.9 | ) | ||||||
Business development transaction costs | — | — | 24.4 | — | ||||||||
Write-off of previously suspended exploration wells | — | — | 13.2 | 4.5 | ||||||||
Mark-to-market loss (gain) on contingent consideration | 8.2 | (4.8 | ) | 8.7 | (4.8 | ) | ||||||
Seal insurance proceeds | — | — | (8.0 | ) | (21.0 | ) | ||||||
Foreign exchange losses (gains) | — | (10.2 | ) | 6.4 | (15.8 | ) | ||||||
Ecuador arbitration settlement | — | — | — | (26.0 | ) | |||||||
Impairment of assets | — | 20.0 | — | 20.0 | ||||||||
Brunei working interest income | — | — | — | (16.0 | ) | |||||||
Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 404.1 | 229.0 | 1,514.3 | 919.8 | |||||||
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 17,617 | 11,814 | 63,128 | 44,598 | ||||||||
Adjusted EBITDA per barrel of oil equivalents sold | $ | 22.94 | 19.39 | 23.99 | 20.63 | |||||||
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.
1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.
15
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION AND EXPLORATION (EBITDAX)
(unaudited)
(Millions of dollars, except per barrel of oil equivalents sold) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||
Net (loss) income attributable to Murphy (GAAP) | $ | (71.7 | ) | 103.4 | 1,149.7 | 411.1 | ||||||
Income tax expense (benefit) | (24.0 | ) | (35.0 | ) | 14.7 | (126.1 | ) | |||||
Interest expense, net | 74.2 | 47.3 | 219.3 | 180.4 | ||||||||
Depreciation, depletion and amortization expense 1 | 310.1 | 199.6 | 1,076.5 | 770.6 | ||||||||
EBITDA attributable to Murphy (Non-GAAP) | 288.6 | 315.3 | 2,460.2 | 1,236.0 | ||||||||
Exploration expenses | 19.5 | 32.5 | 95.1 | 101.8 | ||||||||
EBITDAX attributable to Murphy (Non-GAAP) | 308.1 | 347.8 | 2,555.3 | 1,337.8 | ||||||||
Discontinued operations (income) loss | (36.9 | ) | (64.2 | ) | (1,064.5 | ) | (250.3 | ) | ||||
Accretion of asset retirement obligations | 10.7 | 7.9 | 40.5 | 27.1 | ||||||||
Mark-to-market loss (gain) on crude oil derivative contracts | 133.5 | (35.0 | ) | 33.4 | (33.9 | ) | ||||||
Business development transaction costs | — | — | 24.4 | — | ||||||||
Mark-to-market loss (gain) on contingent consideration | 8.2 | (4.8 | ) | 8.7 | (4.8 | ) | ||||||
Seal insurance proceeds | — | — | (8.0 | ) | (21.0 | ) | ||||||
Foreign exchange losses (gains) | — | (10.2 | ) | 6.4 | (15.8 | ) | ||||||
Ecuador arbitration settlement | — | — | — | (26.0 | ) | |||||||
Impairment of assets | — | 20.0 | — | 20.0 | ||||||||
Brunei working interest income | — | — | — | (16.0 | ) | |||||||
Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 423.6 | 261.5 | 1,596.2 | 1,017.1 | |||||||
Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 17,617 | 11,814 | 63,128 | 44,598 | ||||||||
Adjusted EBITDAX per barrel of oil equivalents sold | $ | 24.05 | 22.14 | 25.29 | 22.81 | |||||||
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.
1 Depreciation, depletion, and amortization expense used in the computation of EBITDA excludes the portion attributable to the non-controlling interest.
16
MURPHY OIL CORPORATION
FUNCTIONAL RESULTS OF OPERATIONS (unaudited)
Three Months Ended December 31, 2019 | Three Months Ended December 31, 2018 | ||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | |||||
Exploration and production | |||||||||
United States1 | $ | 632.7 | 98.4 | 361.0 | 42.6 | ||||
Canada | 123.2 | 3.2 | 113.0 | 4.4 | |||||
Other | 3.7 | (18.1 | ) | 2.3 | 12.3 | ||||
Total exploration and production | 759.6 | 83.5 | 476.3 | 59.3 | |||||
Corporate | (122.1 | ) | (174.8 | ) | 27.3 | (11.7 | ) | ||
Revenue/income from continuing operations | 637.5 | (91.3 | ) | 503.6 | 47.6 | ||||
Discontinued operations, net of tax 2 | — | 36.9 | — | 64.2 | |||||
Total revenues/net income (loss) including noncontrolling interest | $ | 637.5 | (54.4 | ) | 503.6 | 111.8 | |||
Net (loss) income attributable to Murphy | (71.7 | ) | 103.4 | ||||||
Year Ended December 31, 2019 | Year Ended December 31, 2018 | ||||||||
(Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | |||||
Exploration and production | |||||||||
United States1 | $ | 2,367.0 | 518.4 | 1,332.7 | 242.9 | ||||
Canada | 447.0 | (4.3 | ) | 470.5 | 51.1 | ||||
Other | 11.6 | (53.5 | ) | 22.2 | (16.6 | ) | |||
Total exploration and production | 2,825.6 | 460.6 | 1,825.4 | 277.4 | |||||
Corporate | 3.5 | (271.8 | ) | (34.0 | ) | (108.3 | ) | ||
Revenue/income from continuing operations | 2,829.1 | 188.8 | 1,791.4 | 169.1 | |||||
Discontinued operations, net of tax 2 | — | 1,064.5 | — | 250.3 | |||||
Total revenues/net income (loss) including noncontrolling interest | $ | 2,829.1 | 1,253.3 | 1,791.4 | 419.4 | ||||
Net income attributable to Murphy | 1,149.7 | 411.1 | |||||||
1 Includes results attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
2 Malaysia is reported as discontinued operations in current and comparative periods effective January 1, 2019.
17
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
THREE MONTHS ENDED DECEMBER 31, 2019, AND 2018
(Millions of dollars) | United States 1 | Canada | Other | Total | |||||
Three Months Ended December 31, 2019 | |||||||||
Oil and gas sales and other operating revenues | $ | 632.7 | 123.2 | 3.7 | 759.6 | ||||
Lease operating expenses | 153.2 | 35.3 | 0.2 | 188.7 | |||||
Severance and ad valorem taxes | 10.6 | 0.4 | — | 11.0 | |||||
Transportation, gathering and processing | 37.4 | 10.2 | — | 47.6 | |||||
Depreciation, depletion and amortization | 260.1 | 61.4 | 0.6 | 322.1 | |||||
Accretion of asset retirement obligations | 9.2 | 1.5 | — | 10.7 | |||||
Exploration expenses | |||||||||
Geological and geophysical | (2.3 | ) | 0.1 | 6.8 | 4.6 | ||||
Other exploration | 2.3 | 0.2 | 6.4 | 8.9 | |||||
— | 0.3 | 13.2 | 13.5 | ||||||
Undeveloped lease amortization | 5.1 | 0.3 | 0.9 | 6.3 | |||||
Total exploration expenses | 5.1 | 0.6 | 14.1 | 19.8 | |||||
Selling and general expenses | 21.4 | 8.7 | 5.2 | 35.3 | |||||
Other | 14.7 | 0.8 | 0.4 | 15.9 | |||||
Results of operations before taxes | 121.0 | 4.3 | (16.8 | ) | 108.5 | ||||
Income tax provisions (benefits) | 22.6 | 1.1 | 1.3 | 25.0 | |||||
Results of operations (excluding corporate overhead and interest) | $ | 98.4 | 3.2 | (18.1 | ) | 83.5 | |||
Three Months Ended December 31, 2018 | |||||||||
Oil and gas sales and other operating revenues | $ | 361.0 | 113.0 | 2.3 | 476.3 | ||||
Lease operating expenses | 67.9 | 31.6 | 0.4 | 99.9 | |||||
Severance and ad valorem taxes | 11.7 | 0.3 | — | 12.0 | |||||
Transportation, gathering and processing | 17.0 | 8.2 | — | 25.2 | |||||
Depreciation, depletion and amortization | 137.1 | 61.3 | 1.0 | 199.4 | |||||
Accretion of asset retirement obligations | 6.0 | 1.9 | — | 7.9 | |||||
Impairment of assets | 20.0 | — | — | 20.0 | |||||
Exploration expenses | |||||||||
Dry holes and previously suspended exploration costs | 16.0 | — | — | 16.0 | |||||
Geological and geophysical | 0.6 | — | 2.4 | 3.0 | |||||
Other exploration | 1.1 | 0.3 | 3.5 | 4.9 | |||||
17.7 | 0.3 | 5.9 | 23.9 | ||||||
Undeveloped lease amortization | 7.6 | 0.3 | 0.7 | 8.6 | |||||
Total exploration expenses | 25.3 | 0.6 | 6.6 | 32.5 | |||||
Selling and general expenses | 10.0 | 6.1 | 5.4 | 21.5 | |||||
Other | 10.8 | 1.7 | 1.2 | 13.7 | |||||
Results of operations before taxes | 55.2 | 1.3 | (12.3 | ) | 44.2 | ||||
Income tax provisions (benefits) | 12.6 | (3.1 | ) | (24.6 | ) | (15.1 | ) | ||
Results of operations (excluding corporate overhead and interest) | $ | 42.6 | 4.4 | 12.3 | 59.3 | ||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
18
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS (unaudited)
YEAR ENDED DECEMBER 31, 2019, AND 2018
(Millions of dollars) | United States 1 | Canada | Other | Total | |||||
Year Ended December 31, 2019 | |||||||||
Oil and gas sales and other operating revenues | $ | 2,367.0 | 447.0 | 11.6 | 2,825.6 | ||||
Lease operating expenses | 461.5 | 142.4 | 1.3 | 605.2 | |||||
Severance and ad valorem taxes | 46.6 | 1.4 | — | 48.0 | |||||
Transportation, gathering and processing | 140.8 | 35.5 | — | 176.3 | |||||
Depreciation, depletion and amortization | 878.7 | 243.0 | 3.5 | 1,125.2 | |||||
Accretion of asset retirement obligations | 34.4 | 6.1 | — | 40.5 | |||||
Exploration expenses | |||||||||
Dry holes and previously suspended exploration costs | (0.2 | ) | — | 13.1 | 12.9 | ||||
Geological and geophysical | 13.8 | 0.1 | 14.9 | 28.8 | |||||
Other exploration | 7.8 | 0.5 | 17.3 | 25.6 | |||||
21.4 | 0.6 | 45.3 | 67.3 | ||||||
Undeveloped lease amortization | 23.1 | 1.3 | 3.6 | 28.0 | |||||
Total exploration expenses | 44.5 | 1.9 | 48.9 | 95.3 | |||||
Selling and general expenses | 74.3 | 30.0 | 22.5 | 126.8 | |||||
Other | 52.2 | (6.1 | ) | 1.3 | 47.4 | ||||
Results of operations before taxes | 634.0 | (7.2 | ) | (65.9 | ) | 560.9 | |||
Income tax provisions (benefits) | 115.6 | (2.9 | ) | (12.4 | ) | 100.3 | |||
Results of operations (excluding corporate overhead and interest) | $ | 518.4 | (4.3 | ) | (53.5 | ) | 460.6 | ||
Year Ended December 31, 2018 | |||||||||
Oil and gas sales and other operating revenues | $ | 1,332.7 | 470.5 | 22.2 | 1,825.4 | ||||
Lease operating expenses | 230.5 | 122.6 | 0.7 | 353.8 | |||||
Severance and ad valorem taxes | 50.9 | 1.2 | — | 52.1 | |||||
Transportation, gathering and processing | 43.1 | 31.9 | — | 75.0 | |||||
Depreciation, depletion and amortization | 519.5 | 232.4 | 3.5 | 755.4 | |||||
Accretion of asset retirement obligations | 19.5 | 7.7 | — | 27.2 | |||||
Impairment of assets | 20.0 | — | — | 20.0 | |||||
Exploration expenses | |||||||||
Dry holes and previously suspended exploration costs | 16.0 | — | 4.5 | 20.5 | |||||
Geological and geophysical | 7.1 | — | 6.7 | 13.8 | |||||
Other exploration | 6.3 | 0.6 | 20.4 | 27.3 | |||||
29.4 | 0.6 | 31.6 | 61.6 | ||||||
Undeveloped lease amortization | 36.8 | 0.8 | 2.5 | 40.1 | |||||
Total exploration expenses | 66.2 | 1.4 | 34.1 | 101.7 | |||||
Selling and general expenses | 49.0 | 26.8 | 23.5 | 99.3 | |||||
Other | 23.0 | (19.1 | ) | 2.3 | 6.2 | ||||
Results of operations before taxes | 311.0 | 65.6 | (41.9 | ) | 334.7 | ||||
Income tax provisions (benefits) | 68.1 | 14.5 | (25.3 | ) | 57.3 | ||||
Results of operations (excluding corporate overhead and interest) | $ | 242.9 | 51.1 | (16.6 | ) | 277.4 | |||
19
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES
(unaudited)
(Dollars per barrel of oil equivalents sold) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||
Continuing operations | ||||||||||||
United States – Eagle Ford Shale | ||||||||||||
Lease operating expense | $ | 8.11 | 10.83 | 8.70 | 8.84 | |||||||
Severance and ad valorem taxes | 2.32 | 3.13 | 2.82 | 3.20 | ||||||||
Depreciation, depletion and amortization (DD&A) expense | 24.83 | 24.41 | 24.19 | 24.54 | ||||||||
United States – Gulf of Mexico | ||||||||||||
Lease operating expense | $ | 13.84 | 9.16 | 10.89 | 11.39 | |||||||
DD&A expense | 17.47 | 15.32 | 16.43 | 16.50 | ||||||||
Canada – Onshore | ||||||||||||
Lease operating expense | $ | 5.73 | 4.04 | 5.49 | 4.52 | |||||||
Severance and ad valorem taxes | 0.07 | 0.06 | 0.07 | 0.06 | ||||||||
DD&A expense | 10.59 | 10.99 | 10.94 | 10.61 | ||||||||
Canada – Offshore | ||||||||||||
Lease operating expense | $ | 9.76 | 21.85 | 14.95 | 15.21 | |||||||
DD&A expense | 12.30 | 14.45 | 13.07 | 13.68 | ||||||||
Total oil and gas continuing operations | ||||||||||||
Lease operating expense | $ | 10.09 | 8.20 | 8.95 | 7.87 | |||||||
Severance and ad valorem taxes | 0.59 | 0.98 | 0.71 | 1.16 | ||||||||
DD&A expense | 17.56 | 16.78 | 16.98 | 17.25 | ||||||||
Total oil and gas continuing operations – excluding noncontrolling interest | ||||||||||||
Lease operating expense | $ | 9.76 | 8.24 | 8.81 | 7.87 | |||||||
Severance and ad valorem taxes | 0.62 | 1.01 | 0.76 | 1.17 | ||||||||
DD&A expense | 17.60 | 16.90 | 17.05 | 17.28 | ||||||||
20
MURPHY OIL CORPORATION
OTHER FINANCIAL DATA
(unaudited)
(Millions of dollars) | Three Months Ended December 31, | Year Ended December 31, | ||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||
Capital expenditures for continuing operations | ||||||||||||
Exploration and production | ||||||||||||
United States 1 | $ | 248.2 | 934.5 | 2,290.5 | 1,389.1 | |||||||
Canada | 88.7 | 86.8 | 290.3 | 378.1 | ||||||||
Other | 25.7 | 12.7 | 102.4 | 51.6 | ||||||||
Total | 362.6 | 1,034.0 | 2,683.2 | 1,818.8 | ||||||||
Corporate | 6.5 | 4.0 | 15.0 | 22.7 | ||||||||
Total capital expenditures - continuing operations 2 | 369.1 | 1,038.0 | 2,698.2 | 1,841.5 | ||||||||
Charged to exploration expenses 3 | ||||||||||||
United States | — | 17.7 | 21.4 | 29.4 | ||||||||
Canada | 0.3 | 0.3 | 0.6 | 0.6 | ||||||||
Other | 13.2 | 5.9 | 45.3 | 31.6 | ||||||||
Total charged to exploration expenses - continuing operations | 13.5 | 23.9 | 67.3 | 61.6 | ||||||||
Total capitalized | $ | 355.6 | 1,014.1 | 2,630.9 | 1,779.9 | |||||||
1 Includes $34.8 million and $1,261.1 million for acquisition of exploration and production properties in the US Gulf of Mexico in the three months and year ended December 31, 2019, respectively.
2 Includes noncontrolling interest (NCI) capital expenditures of $6.0 million and $34.8 million for the three months and year ended December 31, 2019. Also includes capital expenditures of $96.2 million and $119.6 million for the three months and year ended December 31, 2019 associated with the Kings Quay project. Full year capital expenditures, excluding proved property additions of $1,261.1 million and NCI of $34.8 million, is $1,402.3 million.
3 Excludes amortization of undeveloped leases of $6.3 million and $8.6 million for the three months ended December 31, 2019 and 2018, respectively, and $28.0 million and $40.1 million for the year ended December 31, 2019 and 2018, respectively.
21
MURPHY OIL CORPORATION
CONDENSED BALANCE SHEETS (unaudited)
(Millions of dollars) | December 31, 2019 | December 31, 2018 1 | ||||
Assets | ||||||
Cash and cash equivalents | $ | 306.8 | 359.9 | |||
Assets held for sale | 123.9 | 173.9 | ||||
Other current assets | 543.7 | 346.1 | ||||
Property, plant and equipment – net | 9,969.7 | 8,432.1 | ||||
Non-current assets held for sale | — | 1,545.0 | ||||
Other long-term assets | 774.4 | 195.6 | ||||
Total assets | $ | 11,718.5 | 11,052.6 | |||
Liabilities and Equity | ||||||
Current maturities of long-term debt | $ | — | 0.7 | |||
Liabilities associated with assets held for sale | 13.3 | 286.5 | ||||
Other current liabilities | 929.5 | 559.0 | ||||
Long-term debt | 2,803.4 | 3,109.3 | ||||
Non-current liabilities associated with assets held for sale | — | 392.7 | ||||
Other long-term liabilities | 2,167.7 | 1,506.8 | ||||
Total equity 2,3 | 5,804.6 | 5,197.6 | ||||
Total liabilities and equity | $ | 11,718.5 | 11,052.6 | |||
1 Reclassified to conform to current presentation.
2 Includes noncontrolling interest of $337.2 million and $368.3 million as of December 31, 2019 and December 31, 2018, respectively.
3 Number of shares of Common Stock, $1.00 par value, outstanding at December 31, 2019 was 152,935,361.
22
MURPHY OIL CORPORATION
PRODUCTION SUMMARY
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | |||||||||||
Barrels per day unless otherwise noted | 2019 | 2018 | 2019 | 2018 | ||||||||
Continuing operations | ||||||||||||
Net crude oil and condensate | ||||||||||||
United States | Onshore | 38,500 | 29,609 | 34,578 | 31,787 | |||||||
Gulf of Mexico 1 | 74,409 | 32,412 | 66,823 | 18,702 | ||||||||
Canada | Onshore | 5,812 | 7,017 | 6,329 | 5,690 | |||||||
Offshore | 7,257 | 5,109 | 6,543 | 6,701 | ||||||||
Other | 569 | 537 | 469 | 558 | ||||||||
Total net crude oil and condensate - continuing operations | 126,547 | 74,684 | 114,742 | 63,438 | ||||||||
Net natural gas liquids | ||||||||||||
United States | Onshore | 6,056 | 6,049 | 5,731 | 6,578 | |||||||
Gulf of Mexico 1 | 7,037 | 1,312 | 4,894 | 1,147 | ||||||||
Canada | Onshore | 1,457 | 1,273 | 1,263 | 1,073 | |||||||
Total net natural gas liquids - continuing operations | 14,550 | 8,634 | 11,888 | 8,798 | ||||||||
Net natural gas – thousands of cubic feet per day | ||||||||||||
United States | Onshore | 32,145 | 30,356 | 30,692 | 31,832 | |||||||
Gulf of Mexico 1 | 75,922 | 15,970 | 52,068 | 14,356 | ||||||||
Canada | Onshore | 283,670 | 267,421 | 271,355 | 266,416 | |||||||
Total net natural gas - continuing operations | 391,737 | 313,747 | 354,115 | 312,604 | ||||||||
Total net hydrocarbons - continuing operations including NCI 2,3 | 206,387 | 135,609 | 185,649 | 124,337 | ||||||||
Noncontrolling interest | ||||||||||||
Net crude oil and condensate – barrels per day | (11,255 | ) | (4,500 | ) | (11,226 | ) | (1,134 | ) | ||||
Net natural gas liquids – barrels per day | (539 | ) | (94 | ) | (507 | ) | (24 | ) | ||||
Net natural gas – thousands of cubic feet per day 2 | (4,059 | ) | (1,705 | ) | (3,965 | ) | (430 | ) | ||||
Total noncontrolling interest | (12,471 | ) | (4,878 | ) | (12,394 | ) | (1,230 | ) | ||||
Total net hydrocarbons - continuing operations excluding NCI 2,3 | 193,916 | 130,731 | 173,255 | 123,107 | ||||||||
Discontinued operations | ||||||||||||
Net crude oil and condensate – barrels per day | — | 27,309 | 12,215 | 28,676 | ||||||||
Net natural gas liquids – barrels per day | — | 1,145 | 325 | 792 | ||||||||
Net natural gas – thousands of cubic feet per day 2 | — | 103,419 | 50,758 | 110,223 | ||||||||
Total discontinued operations | — | 45,691 | 21,000 | 47,839 | ||||||||
Total net hydrocarbons produced excluding NCI 2,3 | 193,916 | 176,422 | 194,255 | 170,946 | ||||||||
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.
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MURPHY OIL CORPORATION
PRICE SUMMARY
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Weighted average Exploration and Production sales prices 1 | |||||||||||||||
Continuing operations | |||||||||||||||
Crude oil and condensate – dollars per barrel | |||||||||||||||
United States | Onshore | $ | 57.18 | 63.99 | $ | 59.45 | $ | 67.80 | |||||||
Gulf of Mexico 2 | 58.94 | 58.38 | 61.09 | 64.52 | |||||||||||
Canada 3 | Onshore | 51.32 | 38.44 | 50.29 | 53.85 | ||||||||||
Offshore | 64.75 | 63.86 | 64.91 | 70.16 | |||||||||||
Other | 87.53 | 68.59 | 74.70 | 71.48 | |||||||||||
Natural gas liquids – dollars per barrel | |||||||||||||||
United States | Onshore | 14.56 | 23.64 | 14.60 | 25.68 | ||||||||||
Gulf of Mexico 2 | 13.57 | 23.36 | 15.10 | 28.27 | |||||||||||
Canada 3 | Onshore | 22.49 | 30.81 | 26.04 | 37.47 | ||||||||||
Natural gas – dollars per thousand cubic feet | |||||||||||||||
United States | Onshore | 2.34 | 3.74 | 2.47 | 3.11 | ||||||||||
Gulf of Mexico 2 | 2.39 | 4.35 | 2.43 | 3.35 | |||||||||||
Canada 3 | Onshore | 1.89 | 2.00 | 1.60 | 1.71 | ||||||||||
1 Effective September 30, 2019, weighted average realized prices are reported excluding transportation, gathering and processing costs. Comparative periods are conformed to current presentation.
2 Prices include the effect of noncontrolling interest share for MP GOM.
3 U.S. dollar equivalent.
24
MURPHY OIL CORPORATION
COMMODITY HEDGE POSITIONS (unaudited)
AS OF JANUARY 29, 2020
Commodity | Type | Volumes (Bbl/d) | Price (USD/Bbl) | Remaining Period | |||||||||||
Area | Start Date | End Date | |||||||||||||
United States | WTI ¹ | Fixed price derivative swap | 45,000 | $56.42 | 1/1/2020 | 12/31/2020 | |||||||||
Volumes (MMcf/d) | Price (CAD/Mcf) | Remaining Period | |||||||||||
Area | Commodity | Type | Start Date | End Date | |||||||||
Montney | Natural Gas | Fixed price forward sales at AECO | 97 | C$2.71 | 1/1/2020 | 3/31/2020 | |||||||
Montney | Natural Gas | Fixed price forward sales at AECO | 59 | C$2.81 | 4/1/2020 | 12/31/2020 | |||||||
1 West Texas Intermediate
25
MURPHY OIL CORPORATION
FIRST QUARTER 2020 GUIDANCE
Oil BOPD | NGLs BOPD | Gas MCFD | Total BOEPD | ||||||||
Production – net | |||||||||||
U.S. – Eagle Ford Shale | 32,100 | 5,400 | 30,400 | 42,600 | |||||||
– Gulf of Mexico excluding NCI | 69,600 | 5,500 | 77,000 | 87,900 | |||||||
Canada – Tupper Montney | — | — | 240,000 | 40,000 | |||||||
– Kaybob Duvernay and Placid Montney | 6,200 | 1,600 | 22,200 | 11,500 | |||||||
– Offshore | 4,500 | — | — | 4,500 | |||||||
Other | 500 | — | — | 500 | |||||||
Total net production (BOEPD) - excluding NCI 1 | 181,000 to 193,000 | ||||||||||
Exploration expense ($ millions) | $28 | ||||||||||
FULL YEAR 2020 GUIDANCE | |||||||||||
Total net production (BOEPD) - excluding NCI 2 | 190,000 to 202,000 | ||||||||||
Capital expenditures – excluding NCI ($ billions) 3 | $1.4 - $1.5 | ||||||||||
1 Excludes noncontrolling interest of MP GOM of 12,800 BOPD of oil, 600 BOPD of NGLs, and 5,200 MCFD gas. | |||||||||||
2 Excludes noncontrolling interest of MP GOM of 12,600 BOPD of oil, 600 BOPD of NGLs, and 5,600 MCFD gas. | |||||||||||
3 Excludes noncontrolling interest of MP GOM of $62 MM and $3 MM for assets held for sale. | |||||||||||
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