EL DORADO, Ark.--(BUSINESS WIRE)--Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the first quarter ended March 31, 2019, including net income attributable to Murphy of $40 million, or $0.23 per diluted share. Adjusted net income, which excludes discontinued operations and other one-off items, was $27 million, or $0.15 per diluted share.
On March 21, 2019, Murphy announced the divestiture of its Malaysia assets. Beginning with the first quarter 2019, Malaysian operations will be reported as “discontinued operations” and classified as “held for sale” for financial reporting purposes. Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary, will exclude discontinued operations and noncontrolling interest.1
Highlights for the first quarter include:
- Signed a purchase and sale agreement to divest Malaysia assets for $2.127 billion cash, with an expected book gain of $0.9 billion to $1.0 billion
- Realized adjusted EBITDAX over $24 per barrel of oil equivalent sold
- Obtained operatorship approval from regulators for Gulf of Mexico assets acquired from Petrobras America Inc.
Highlights subsequent to quarter end include:
- Signed purchase and sale agreement to acquire accretive, oil-weighted Gulf of Mexico assets for $1.375 billion
- Drilled a discovery in Block 15-1/05 in the Cuu Long Basin in Vietnam with the LDT-1X exploration well
- Entered into 20,000 barrels per day of new fixed price oil swaps for the remainder of 2019 and full year 2020
FIRST QUARTER 2019 RESULTS
The company recorded net income, attributable to Murphy, of $40 million, or $0.23 per diluted share, for the first quarter 2019. The company reported adjusted net income, which excludes both the results of discontinued operations and certain other items that affect comparability of results between periods, of $27 million, or $0.15 per diluted share. The adjusted income from continuing operations excludes the following after-tax items: a $13 million write-off of previously suspended exploration well costs, an $11 million mark-to-market non-cash expense related to the valuation of potential Petrobras America Inc. (“PAI”) contingent consideration, and a $10 million charge for non-recurring PAI transition service fees. Details for first quarter results can be found in the attached schedules.
Adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) from continuing operations attributable to Murphy, totaled $311 million, or $23.00 per barrel of oil equivalent (BOE) sold. Adjusted earnings before interest, taxes, depreciation, amortization and exploration expenses (EBITDAX) from continuing operations attributable to Murphy, totaled $330 million, or $24.43 per BOE sold. Details for first quarter EBITDA and EBITDAX reconciliation can be found in the attached schedules.
Production from continuing operations in the first quarter averaged 148 thousand barrels of oil equivalent per day (MBOEPD) with production from discontinued operations averaging 44 MBOEPD. Production from continuing operations was below plan due to the following reasons; North American onshore business production was lower than expected by 4,400 BOEPD, with the majority in the Eagle Ford Shale where 3,500 BOEPD was due to a significant delay in the execution of a ten well pad along with offset frac impacts. Production levels were also impacted by higher than planned downtime at key facilities along with historically higher than normal failure rates on artificial lift systems that impacted high volume wells. The onshore Canada business was lower than expected by 900 BOEPD due primarily to third party mid-stream specification constraints causing production from three new high-rate Kaybob Duvernay wells to be shut in coupled with cold weather in the region causing unplanned shut ins. The North American offshore business had a negative variance of 2,100 BOEPD of which 1,500 BOEPD was the result of a royalty adjustment due to cumulative production levels in a newly acquired Gulf of Mexico field, and lower than planned production levels at other smaller Gulf of Mexico fields.
Details for first quarter production can be found in the attached schedules.
“The first quarter was an extremely busy quarter at Murphy. We demonstrated again that we are proven deal-makers by successfully executing agreements to divest our Malaysia assets, which are becoming gassier, followed shortly thereafter by an agreement to re-deploy the expected proceeds by acquiring oil-weighted, tax-advantaged Gulf of Mexico assets further enhancing our ability to generate cash flow. While our lower than planned production across our North American business was disappointing, many of the causes were one-off events and are now behind us with production stabilized as we move into the second quarter. As always, we remain committed to rewarding shareholders with cash returns through our long-standing competitive dividend, along with beginning to execute our recently Board-approved share repurchase, all while keeping forward investment in our assets in line with cash flows,” stated Roger W. Jenkins, President and Chief Executive Officer.
FINANCIAL POSITION
As of March 31, 2019, the company had $2.8 billion of outstanding long-term, fixed-rate notes, $325 million of borrowings on the $1.6 billion unsecured senior credit facility, and approximately $286 million in cash and cash equivalents, net to Murphy at quarter end. The fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 5.5 percent.
STRATEGIC DIVESTITURE OF MALAYSIA
On March 21, 2019, the company announced it signed a purchase and sale agreement to divest the fully issued share capital of the subsidiaries that own Murphy’s Malaysia assets, to a subsidiary of PTT Exploration and Production Public Company Limited (“PTTEP”). PTTEP will pay Murphy $2.127 billion in an all-cash transaction, payable upon closing and subject to customary closing adjustments, plus up to a $100 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020. The transaction has an effective economic valuation date of January 1, 2019.
Since announcing the divestiture, significant progress has been made toward a closing in the second quarter 2019. Closing of the transaction is subject to customary conditions precedent including, among other things, necessary regulatory approvals. Under the terms of the transaction, Murphy will exit the country of Malaysia. The expected gain on the sale of the assets is estimated to be between $0.9 billion to $1.0 billion.
At year end 2018, the proved reserves (1P) net to Murphy attributable to Malaysia, were 129 million barrels of oil equivalent (Mmboe), which represented 16 percent of the company’s total proved reserves at that time. Of the 129 Mmboe of proved reserves, 70 Mmboe are characterized as proved undeveloped. The proved reserves are comprised of 78 Mmboe of natural gas and 51 million barrels (Mmbbl) of liquids. As previously disclosed, full year 2019 production from Malaysia was estimated to be 46 to 48 MBOEPD.
SUBSEQUENT TO QUARTER END
Subsequent to quarter end, Murphy announced that its wholly owned subsidiary, Murphy Exploration & Production Company – USA, has entered into a definitive agreement to acquire deep water Gulf of Mexico assets from LLOG Exploration Offshore, L.L.C. and LLOG Bluewater Holdings, L.L.C., (“LLOG”). The accretive, cash flow providing Gulf of Mexico assets currently produce approximately 38,000 BOEPD and are expected to add approximately 66 Mmboe of proved reserves and 122 Mmboe of proved and probable (2P) reserves2. The proved reserves are comprised of 16 Mmboe of natural gas and 51 Mmbbl of liquids. The transaction will have an effective date of January 1, 2019 and is expected to close in the second quarter, subject to normal closing adjustments. The new assets have an estimated 2019 annualized production range of 32 to 35 MBOEPD.
Murphy will pay a cash consideration of $1.375 billion. Additional contingent consideration payments are based on the following: up to $200 million in the event that revenue from certain properties exceeds certain contractual thresholds between 2019 and 2022; $50 million following first oil from certain development projects.
“Over the past seven months Murphy has undertaken three major transactions as part of the strategic transformation to focus our company primarily in the western hemisphere with oil-weighted growth that can generate significant after tax cash flow for many years. Viewed in combination, our sale of Malaysia along with the purchase of two Gulf of Mexico assets illustrates very compelling metrics across all fronts. We look forward to closing the transactions during the second quarter and executing on our new long range plan,” stated Jenkins.
REGIONAL OPERATIONS SUMMARY
North American Onshore
The North American onshore business produced approximately 86 MBOEPD in the first quarter.
Eagle Ford Shale – Production in the quarter averaged approximately 36 MBOEPD, with 86 percent liquids. The company brought 13 operated wells online during the quarter, of which four were in the Tilden area and nine were in the Karnes area. The nine Karnes wells were completed with four in the Upper Eagle Ford Shale and five in the Lower Eagle Ford Shale, and due to a variety of delays, flowed only two days in the quarter. The nine new wells had high 30 day (IP30 rate) rates averaging over 1,700 BOEPD, with the Upper Eagle Ford Shale wells averaging over 1,400 BOEPD IP30 with the Lower Eagle Ford Shale wells average exceeding 2,100 BOEPD. The 2019 Eagle Ford Shale drilling and completion schedule has been amended to include a slightly higher average well count per pad. As compared to the original plan, the company now plans to bring two additional wells online, bringing the total wells online to 92.
“Following a weak production month for March in our Eagle Ford Shale business we are back on track with production increasing daily as volumes are currently approaching 44,000 BOEPD. With almost 80 percent of our planned wells to come online in the second and third quarters, we expect to see continued strong growth in this asset,” commented Jenkins.
Tupper Montney – Natural gas production in the quarter averaged 223 million cubic feet per day (MMCFD). As planned, the company brought three operated wells online during the quarter. As a result of the company’s sales price diversification and hedging strategy, Murphy achieved a natural gas price of C$2.98 per million cubic feet per day AECO for the Tupper Montney.
Kaybob Duvernay – During the quarter production averaged approximately 10 MBOEPD with 61 percent liquids. As planned, the company brought four operated wells online: a three well pad in Simonette and one well in Kaybob North. Due to a third party mid-stream specification constraint, the three well pad in Simonette was unable to flow to sales for the entire quarter. For future production forecasts, it is assumed that the three wells will not produce for the remainder of the year. The one well in Kaybob North achieved an IP30 rate of over 830 BOEPD with 89 liquids with restricted flow rates.
As a result of reviewing land retention plans and capital allocation, Murphy has elected to drill and complete fewer wells in the Kaybob Duvernay based on the current market conditions. The company expects to bring seven wells online as compared to the previously planned twelve wells. The lower well count also includes the three well pad that was unable to flow due to third party mid-stream constraints.
Global Offshore
The offshore business produced 62 MBOEPD for the first quarter, with 96 percent liquids. This excludes production from discontinued operations.
North America – Production in the quarter for the Gulf of Mexico averaged 54 MBOEPD, with 95 percent liquids. Canada offshore averaged 8 MBOEPD.
Significant planning for 2019 rig operations took place in the first quarter. The company has solidified its rig and partner plans to drill a development well at Dalmatian field in the second quarter. That operation will be followed by the drilling of the Hoffe Park exploration well in Mississippi Canyon 122. Following that exploration well, the contracted rig will move onto the Cascade #5 well to repair a subsea safety valve that is expected to revive production levels, with an anticipated increase of approximately 7,500 BOEPD gross. In additional development work, there will be a rig placed on the Medusa facility late in the second quarter for a one well workover. A different rig will move to Front Runner to sidetrack and complete a three well program commencing in the fourth quarter.
Vietnam – Early in 2019, Murphy received the Declaration of Commerciality for the LDV field and expects to move forward with sanction of the field development later this year.
EXPLORATION
Mexico Exploration – During the first quarter, the company drilled a discovery with its first exploration test on Block 5 in the Salinas Basin, offshore Mexico. The Cholula-1EXP exploration well reached a total depth (TD) of over 8,800 feet in approximately 2,300 feet of water. The well was spud and drilled to total depth in less than 30 days with a drilling cost of approximately $12 million net to Murphy. The exploration well discovered hydrocarbons in the upper Miocene target objectives, encountering approximately 185 feet of net pay. The results of the well have significantly de-risked the block and the company is currently evaluating future appraisal plans. Murphy’s subsidiary, Murphy Sur, S. de R.L. de C.V., is the operator of Block 5 holding a 30 percent working interest (WI). Partners in the block are wholly-owned subsidiaries of Petrolium Nasional Berhad (“PETRONAS”) (23.34 percent WI), Ophir Energy (23.33 percent WI) and Sierra Oil and Gas (23.33 percent WI).
Vietnam Exploration – Murphy drilled a discovery in the LDT-1X exploration well in Block 15-1/05 in the Cuu Long Basin in Vietnam. The well completed drilling operations in April drilling to a TD of 14,090 feet measured depth at a net cost to Murphy of approximately $13 million. The well successfully encountered approximately 320 feet of net oil pay in the primary objective and an additional 62 feet of net oil pay in a secondary objective. The LDT-1X discovery will be incorporated into the development of the adjacent LDV field where Murphy is operator and progressing toward first oil in 2021. Murphy’s subsidiary, Murphy Cuu Long Bac Oil Co., Ltd, is the operator of the block and holds 40 percent WI in Block 15-1/05. Partners in the block include PetroVietnam Exploration and Production Company (“PVEP”) with 35 percent carried interest and SK Innovation (“SKI”) with a 25 percent interest.
“I am extremely pleased with the early success of our 2019 exploration program. Our drilling team did an outstanding job executing a pace-setter well in Mexico that allows us to dramatically improve the economics for the development of the block. The well confirms our view of the highly prospective Block 5 and, along with our partners, we are planning a Cholula appraisal and further exploration program in 2020. While it is too early to quantify ultimate volumes without additional appraisal, we are excited to have successfully encountered pay in all of our objectives in an oil-charged system. We especially look forward to incorporating the well results into multiple look-a-like prospects that are near the Cholula well,” Jenkins stated. “In Vietnam, the LDT-1X well has met our pre-drill expectations and is a positive resource addition to our growing business in the country, with the oil reservoir section having properties exceeding our pre drill estimates. The data collected from the well also yielded valuable information that will be utilized in future exploration activity on Block 15-1/05.”
Gulf of Mexico Exploration – During the third quarter, Murphy plans to spud the Hoffe Park exploration well in Mississippi Canyon 122 targeting a gross mean volume of 75 Mmboe at a 60 percent working interest.
COMMODITY HEDGE POSITIONS
The company employs derivative commodity instruments to manage certain risks associated with commodity prices and to underpin capital spending associated with certain assets. Subsequent to quarter end, Murphy entered into WTI based fixed price derivative swaps as detailed in the table below.
| Hedge & Fixed Price Sales Open Positions, as of April 30, 2019 | ||||||||||||
| Remaining Period | ||||||||||||
| Area | Commodity | Type |
Volume |
Price |
Start Date | End Date | ||||||
| U.S. | WTI | Fixed Price Derivative Swap | 20,000 | $63.64 | May 1, 2019 | Dec. 31, 2019 | ||||||
| U.S. | WTI | Fixed Price Derivative Swap | 20,000 | $60.10 | Jan. 1, 2020 | Dec. 31, 2020 | ||||||
Currently, Murphy has the following natural gas fixed price forward sales as detailed in the table below.
| Fixed Price Sales Open Positions, as of April 30, 2019 | ||||||||||||
| Remaining Period | ||||||||||||
| Area | Commodity | Type |
Volume |
Price |
Start Date | End Date | ||||||
| Montney | Natural Gas |
Fixed Price Forward |
59 | $2.81 | Jan. 1, 2019 | Dec. 31, 2020 | ||||||
SUSTAINABILITY REPORT
Subsequent to quarter end, Murphy released its 2019 Sustainability Report. This inaugural online report reinforces the strategic importance of responsible oil and natural gas development while investing in local communities. Highlights from the report include; safeguarding people conducting business in a manner that protects the health, safety and security of everyone who works for and alongside Murphy, protecting the environment and practicing conservation by committing to minimize environmental impact through comprehensive policies, resource efficiency, and emission reduction programs; and, investing in and engaging with local communities where Murphy employees live and work with the commitment to making a lasting difference.
To view an electronic version of Murphy’s 2019 Sustainability Report, visit www.murphyoilcorp.com/Responsibility/.
2019 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Murphy’s previously disclosed capital program had a range of $1.25 to $1.45 billion. The Malaysia business as previously disclosed had a capital program of $109 million. With Malaysia capital removed, the new range of estimated capital spend for continuing operations is $1.15 to $1.35 billion. This range does not include new capital that will be allocated to the recently announcement agreement to acquire Gulf of Mexico assets as the company will update upon the closing. Full year production guidance will be updated following the closing of the recently announced Gulf of Mexico acquisition.
For the second quarter Murphy estimates that production will be 143 to 147 MBOEPD. This level of production is below that of the first quarter due to significant planned downtime events at the non-operated St. Malo field where planned maintenance is scheduled for approximately 22 days as well as a planned outage at the Tupper Montney non-operated gas plants for approximately 11 days in the second quarter. The company has historically experienced major planned downtime events in the second quarter of each year associated with offshore assets and as such, second quarter production has been lower than the first quarter for three of the last four years.
The operated onshore well cadence for the year is updated to include the following revisions, two additional Eagle Ford Wells and six less wells it the Kaybob Duvernay.
| 2019 Operated Onshore Wells Online | |||||||||||||||
| 1Q 2019A | 2Q 2019E | 3Q 2019E | 4Q 2019E | 2019 TotalE | |||||||||||
| Eagle Ford Shale | 13 | 23 | 35 | 21 | 92 | ||||||||||
| Kaybob Duvernay | 1 | 6 | 0 | 0 | 7 | ||||||||||
| Tupper Montney | 3 | 0 | 5 | 0 | 8 | ||||||||||
| Placid Montney | 0 | 0 | 0 | 7 | 7 | ||||||||||
“At this time our capital and production ranges are simply a reduction of our discontinued operations in Malaysia being removed from our ongoing business. We are especially keen to maintain capital spending for our continuing business at planned levels and annual production guidance will be updated following the closing of our latest Gulf of Mexico transaction later this quarter. As usual, our goal remains to keep spending levels, including our dividend in line with cash flow,” commented Jenkins.
Detailed guidance for the second quarter is contained in the following schedule.
CONFERENCE CALL AND WEBCAST SCHEDULED FOR MAY 2, 2019
Murphy will host a conference call to discuss first quarter 2019 financial and operating results on Thursday, May 2, 2019, at 10:00 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 11507639.
FINANCIAL DATA
Summary financial data and operating statistics for first 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 and schedules comparing EBITDA and EBITDAX between periods are included with these schedules as well as guidance for the second quarter 2019.
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 new 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.
2Transaction reserves are based on internal engineering estimates as of January 1, 2019, using strip prices in effect on April 3, 2019.
ABOUT MURPHY OIL CORPORATION
Murphy Oil Corporation is a global independent oil and natural gas exploration and production company. The company’s diverse resource base includes production from North America onshore plays in the Eagle Ford Shale, Kaybob Duvernay, Tupper Montney and Placid Montney, as well as offshore Gulf of Mexico, Canada and Southeast Asia. Additional information is available on the company’s website 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: our ability to complete the acquisition of the Gulf of Mexico assets or the Malaysia divestiture due to the failure to obtain regulatory approvals, the failure of the respective counterparties to perform their obligations under the relevant transaction agreements, the failure to satisfy all closing conditions, or otherwise, 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; and 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 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 good 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, although 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.
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MURPHY OIL CORPORATION |
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SUMMARIZED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) |
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|
(Thousands of dollars, except per share amounts) |
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| Three Months Ended | |||||||
| March 31, | |||||||
| 2019 |
2018 1 |
||||||
| Revenues | |||||||
| Revenue from sales to customers | $ | 590,550 | 396,329 | ||||
|
Loss on crude contracts |
- | (29,502 | ) | ||||
| Gain on sale of assets and other income | 454 | 7,963 | |||||
| Total revenues | 591,004 | 374,790 | |||||
| Costs and expenses | |||||||
| Lease operating expenses | 131,696 | 88,833 | |||||
| Severance and ad valorem taxes | 10,097 | 12,157 | |||||
|
Exploration expenses, including undeveloped lease amortization |
32,538 | 28,738 | |||||
| Selling and general expenses | 63,360 | 48,096 | |||||
| Depreciation, depletion and amortization | 229,406 | 182,743 | |||||
| Accretion of asset retirement obligations | 9,340 | 6,372 | |||||
| Other expense (benefit) | 30,005 | (11,045 | ) | ||||
| Total costs and expenses | 506,442 | 355,894 | |||||
| Operating income from continuing operations | 84,562 | 18,896 | |||||
| Other income (loss) | |||||||
| Interest and other income (loss) | (4,748 | ) | 4,587 | ||||
| Interest expense, net | (46,069 | ) | (44,541 | ) | |||
| Total other loss | (50,817 | ) | (39,954 | ) | |||
|
Income (loss) from continuing operations before income taxes |
33,745 | (21,058 | ) | ||||
|
Income tax expense (benefit) |
10,822 | (111,639 | ) | ||||
| Income from continuing operations | 22,923 | 90,581 | |||||
|
Income from discontinued operations, net of income taxes |
49,846 | 77,672 | |||||
| Net income including noncontrolling interest | 72,769 | 168,253 | |||||
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Less: Net income attributable to noncontrolling interest |
32,587 | - | |||||
| NET INCOME ATTRIBUTABLE TO MURPHY | $ | 40,182 | 168,253 | ||||
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INCOME (LOSS) PER COMMON SHARE – BASIC |
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| Continuing operations | $ | (0.06 | ) | 0.52 | |||
| Discontinued operations | 0.29 | 0.45 | |||||
| Net Income | $ | 0.23 | 0.97 | ||||
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INCOME (LOSS) PER COMMON SHARE – DILUTED |
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| Continuing operations | $ | (0.06 | ) | 0.52 | |||
| Discontinued operations | 0.29 | 0.44 | |||||
| Net Income | $ | 0.23 | 0.96 | ||||
| Cash dividends per Common share | 0.25 | 0.25 | |||||
| Average Common shares outstanding (thousands) | |||||||
| Basic | 173,341 | 172,805 | |||||
| Diluted |
174,491 |
174,620 | |||||
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1 Reclassified to conform to current presentation. |
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MURPHY OIL CORPORATION |
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CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) |
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(Thousands of dollars) |
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| Three Months Ended | |||||||
| March 31, | |||||||
| 2019 |
2018 1 |
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| Operating Activities | |||||||
| Net income including noncontrolling interest | $ | 72,769 | 168,253 | ||||
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Adjustments to reconcile net income to net cash provided by continuing operations activities: |
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| (Income) loss from discontinued operations | (49,846 | ) | (77,672 | ) | |||
| Depreciation, depletion and amortization | 229,406 | 182,743 | |||||
| Previously suspended exploration costs (credits) | 13,251 | (5 | ) | ||||
| Amortization of undeveloped leases | 8,045 | 13,168 | |||||
| Accretion of asset retirement obligations | 9,340 | 6,372 | |||||
| Deferred income tax charge (benefit) | 15,589 | (147,716 | ) | ||||
| Pretax (gain) loss from sale of assets | (12 | ) | 339 | ||||
| Mark to market and revaluation of contingent consideration | 13,530 | – | |||||
| Mark to market of crude contracts | – | 14,350 | |||||
| Long-term non-cash compensation | 22,388 | 14,057 | |||||
| Net (increase) decrease in noncash operating working capital | (98,505 | ) | (3,553 | ) | |||
| Other operating activities, net |
(18,758 |
) |
(59,449 |
) |
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| Net cash provided by continuing operations activities |
217,197 |
110,887 |
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| Investing Activities | |||||||
| Property additions and dry hole costs | (270,338 | ) | (247,054 | ) | |||
| Proceeds from sales of property, plant and equipment | – | 260 | |||||
| Net cash required by investing activities | (270,338 | ) | (246,794 | ) | |||
| Financing Activities | |||||||
| Capital lease obligation payments | (160 | ) | – | ||||
| Withholding tax on stock-based incentive awards | (6,991 | ) | (6,642 | ) | |||
| Distribution to noncontrolling interest | (18,437 | ) | – | ||||
| Cash dividends paid | (43,398 | ) | (43,258 | ) | |||
| Net cash required by financing activities | (68,986 | ) | (49,900 | ) | |||
| Cash Flows from Discontinued Operations | |||||||
| Operating activities |
123,469 |
167,386 |
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| Investing activities | (26,438 | ) | (26,848 | ) | |||
| Financing activities | (2,547 | ) | (2,405 | ) | |||
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Net cash provided by discontinued operations |
94,484 |
138,133 |
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Cash transferred from discontinued operations to continuing operations |
46,080 |
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371,656 |
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| Effect of exchange rate changes on cash and cash equivalents | 2,405 | 21,051 | |||||
| Net increase (decrease) in cash and cash equivalents | (73,642 | ) | 206,900 | ||||
| Cash and cash equivalents at beginning of period | 359,923 | 630,433 | |||||
| Cash and cash equivalents at end of period | $ | 286,281 | 837,333 | ||||
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1 Reclassified to conform to current presentation. |
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SCHEDULE OF ADJUSTED INCOME (LOSS) |
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(unaudited) |
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(Millions of dollars, except per share amounts) |
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| Three Months Ended | |||||||
| March 31, | |||||||
| 2019 | 2018 | ||||||
| Net income attributable to Murphy (GAAP) | $ | 40.2 | 168.3 | ||||
| Discontinued operations loss (income) | (49.8 | ) | (77.7 | ) | |||
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(Loss) income from continuing operations |
(9.6 | ) | 90.6 | ||||
| Adjustments: | |||||||
| Write-off of previously suspended exploration wells | 13.2 | – | |||||
| Mark-to-market (gain) loss on PAI contingent consideration | 10.7 | – | |||||
| PAI transition service fee | 9.8 | – | |||||
| Foreign exchange losses (gains) | 2.4 | (11.9 | ) | ||||
| Impact of tax reform | – | (120.0 | ) | ||||
| Mark-to-market (gain) loss on crude oil derivative contracts | – | 11.3 | |||||
| Seal insurance proceeds | – | (8.2 | ) | ||||
| Total adjustments after taxes | 36.1 | (128.8 | ) | ||||
| Adjusted income (loss) from continuing operations attributable to Murphy | $ | 26.5 | (38.2 | ) | |||
| Adjusted income (loss) from continuing operations per diluted share | $ | 0.15 | (0.22 | ) | |||
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.
| Three Months Ended | ||||||||
| March 31, 2019 | ||||||||
| Pretax | Tax | Net | ||||||
| Exploration & Production: | ||||||||
| United States | $ | 26.0 | (5.5 | ) | 20.5 | |||
| Other International | 13.2 | – | 13.2 | |||||
| Total E&P | 39.2 | (5.5 | ) | 33.7 | ||||
| Corporate: | 2.6 | (0.2 | ) | 2.4 | ||||
| Total adjustments | $ | 41.8 | (5.7 | ) | 36.1 | |||
|
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 | |||||||
| March 31, | |||||||
| 2019 | 2018 | ||||||
| Net income attributable to Murphy (GAAP) | $ | 40.2 | 168.3 | ||||
| Discontinued operations loss (income) | (49.8 | ) | (77.7 | ) | |||
| Income tax expense (benefit) | 10.8 | (111.6 | ) | ||||
| Interest expense, net | 46.1 | 44.5 | |||||
| Depreciation, depletion and amortization expense | 212.1 | 182.7 | |||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 259.4 | 206.2 | ||||
| Mark-to-market (gain) loss on PAI contingent consideration | 13.5 | – | |||||
| Write-off of previously suspended exploration wells | 13.2 | – | |||||
| PAI transition service fee | 12.5 | – | |||||
| Accretion of asset retirement obligations | 9.3 | 6.4 | |||||
| Foreign exchange losses (gains) | 2.6 | (16.6 | ) | ||||
| Mark-to-market (gain) loss on crude oil derivative contracts | – | 14.4 | |||||
| Seal insurance proceeds | – | (11.3 | ) | ||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 310.5 | 199.1 | ||||
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 13,497.2 | 10,531.7 | |||||
| EBITDA per barrel of oil equivalents sold | $ | 19.22 | 19.58 | ||||
| Adjusted EBITDA per barrel of oil equivalents sold | $ | 23.00 | 18.90 | ||||
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Earnings before interest, taxes, depreciation and amortization (EBITDA) and adjusted EBITDA. Management believes EBITDA and adjusted EBITDA are important information to provide because they are used by management to evaluate the Company's operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. EBITDA and adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (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 EBITDA per barrel of oil equivalent sold and adjusted EBITDA per barrel of oil equivalent sold. Management believes EBITDA per barrel of oil equivalent sold and adjusted EBITDA per barrel of oil equivalent sold are important information because they are used by management to evaluate the Company's profitability of one barrel of oil equivalent sold in that period. EBITDA per barrel of oil equivalent sold and adjusted EBITDA per barrel of oil equivalent sold are non-GAAP financial metrics.
|
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 | |||||||
| March 31, | |||||||
| 2019 | 2018 | ||||||
| Net income attributable to Murphy (GAAP) | $ | 40.2 | 168.3 | ||||
| Discontinued operations loss (income) | (49.8 | ) | (77.7 | ) | |||
| Income tax expense (benefit) | 10.8 | (111.6 | ) | ||||
| Interest expense, net | 46.1 | 44.5 | |||||
| Depreciation, depletion and amortization expense | 212.1 | 182.7 | |||||
| EBITDA attributable to Murphy (Non-GAAP) | 259.4 | 206.2 | |||||
| Exploration expenses | 32.5 | 28.7 | |||||
| EBITDAX attributable to Murphy (Non-GAAP) | $ | 291.9 | 234.9 | ||||
| Mark-to-market (gain) loss on PAI contingent consideration | 13.5 | – | |||||
| PAI transition service fee | 12.5 | – | |||||
| Accretion of asset retirement obligations | 9.3 | 6.4 | |||||
| Foreign exchange losses (gains) | 2.6 | (16.6 | ) | ||||
| Mark-to-market (gain) loss on crude oil derivative contracts | – | 14.4 | |||||
| Seal insurance proceeds | – | (11.3 | ) | ||||
| Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 329.8 | 227.8 | ||||
| Total barrels of oil equivalents sold from continuing operations attributable to Murphy (thousands of barrels) | 13,497.2 | 10,531.7 | |||||
| EBITDAX per barrel of oil equivalents sold | $ | 21.63 | 22.30 | ||||
| Adjusted EBITDAX per barrel of oil equivalents sold | $ | 24.43 | 21.63 | ||||
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX. Management believes EBITDAX and adjusted EBITDAX are important information to provide because they are used by management to evaluate the Company's operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company's financial results. EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for Net income (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 EBITDAX per barrel of oil equivalent sold and adjusted EBITDAX per barrel of oil equivalent sold. Management believes EBITDAX per barrel of oil equivalent sold and adjusted EBITDAX per barrel of oil equivalent sold are important information because they are used by management to evaluate the Company’s profitability of one barrel of oil equivalent sold in that period. EBITDAX per barrel of oil equivalent sold and adjusted EBITDAX per barrel of oil equivalent sold are non-GAAP financial metrics.
|
MURPHY OIL CORPORATION |
|||||||||||||
|
FUNCTIONAL RESULTS OF OPERATIONS (unaudited) |
|||||||||||||
|
(Millions of dollars) |
|||||||||||||
|
Three Months Ended |
Three Months Ended |
||||||||||||
| Revenues |
Income |
Revenues |
Income |
||||||||||
| Exploration and production | |||||||||||||
| United States 1 | $ | 469.2 | 116.2 | 278.1 | 36.2 | ||||||||
| Canada | 118.9 | 7.5 | 118.3 | 24.4 | |||||||||
| Other | 2.9 | (28.3 | ) | – | (15.4 | ) | |||||||
| Total exploration and production | 591.0 | 95.4 | 396.4 | 45.2 | |||||||||
| Corporate | – | (72.4 | ) | (21.6 | ) | 45.4 | |||||||
| Revenue/income from continuing operations | 591.0 | 23.0 | 374.8 | 90.6 | |||||||||
| Discontinued operations, net of tax 2 | – | 49.8 | – | 77.7 | |||||||||
| Total revenues/net income (loss) | $ | 591.0 | 72.8 | 374.8 | 168.3 | ||||||||
|
1 2019 includes results attributable to a noncontrolling interest in MP GOM LLC, a Gulf of Mexico joint venture (MP GOM). |
|||||||||||||
|
2 Malaysia is reported as discontinued operations effective January 1, 2019. |
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|
MURPHY OIL CORPORATION |
|||||||||
|
OIL AND GAS OPERATING RESULTS (unaudited) |
|||||||||
|
THREE MONTHS ENDED MARCH 31, 2019 AND 2018 |
|||||||||
| United | |||||||||
| (Millions of dollars) |
States 1 |
Canada | Other | Total | |||||
| Three Months Ended March 31, 2019 | |||||||||
| Oil and gas sales and other revenues | $ | 469.2 | 118.9 | 2.9 | 591.0 | ||||
| Lease operating expenses | 92.4 | 39.0 | 0.3 | 131.7 | |||||
| Severance and ad valorem taxes | 9.8 | 0.3 | – | 10.1 | |||||
| Depreciation, depletion and amortization | 163.9 | 59.5 | 1.0 | 224.4 | |||||
| Accretion of asset retirement obligations | 7.8 | 1.5 | – | 9.3 | |||||
| Exploration expenses | |||||||||
| Dry holes and previously suspended exploration costs | 0.1 | – | 13.1 | 13.2 | |||||
| Geological and geophysical | 0.5 | – | 5.5 | 6.0 | |||||
| Other exploration | 1.2 | 0.1 | 4.0 | 5.3 | |||||
| 1.8 | 0.1 | 22.6 | 24.5 | ||||||
| Undeveloped lease amortization | 6.9 | 0.3 | 0.8 | 8.0 | |||||
| Total exploration expenses | 8.7 | 0.4 | 23.4 | 32.5 | |||||
| Selling and general expenses | 17.3 | 7.6 | 5.6 | 30.5 | |||||
| Other | 30.6 | 0.2 | 0.3 | 31.1 | |||||
| Results of operations before taxes | 138.7 | 10.4 | (27.7) | 121.4 | |||||
| Income tax provisions (benefits) | 22.5 | 2.9 | 0.6 | 26.0 | |||||
|
Results of operations (excluding corporate overhead and interest) |
$ | 116.2 | 7.5 | (28.3) | 95.4 | ||||
| Three Months Ended March 31, 2018 | |||||||||
| Oil and gas sales and other revenues | $ | 278.1 | 118.3 | – | 396.4 | ||||
| Lease operating expenses | 58.5 | 30.4 | – | 88.9 | |||||
| Severance and ad valorem taxes | 11.8 | 0.4 | – | 12.2 | |||||
| Depreciation, depletion and amortization | 121.6 | 55.7 | 0.8 | 178.1 | |||||
| Accretion of asset retirement obligations | 4.4 | 2.0 | – | 6.4 | |||||
| Exploration expenses | |||||||||
| Geological and geophysical | 5.9 | – | 2.9 | 8.8 | |||||
| Other exploration | 1.2 | 0.1 | 5.4 | 6.7 | |||||
| 7.1 | 0.1 | 8.3 | 15.5 | ||||||
| Undeveloped lease amortization | 12.7 | 0.2 | 0.3 | 13.2 | |||||
| Total exploration expenses | 19.8 | 0.3 | 8.6 | 28.7 | |||||
| Selling and general expenses | 14.4 | 7.7 | 5.9 | 28.0 | |||||
| Other | 0.8 | (11.7) | (0.1) | (11.0) | |||||
|
Results of operations before taxes |
46.8 | 33.5 | (15.2) | 65.1 | |||||
| Income tax provisions (benefits) | 10.6 | 9.1 | 0.2 | 19.9 | |||||
|
Results of operations (excluding corporate overhead and interest) |
$ | 36.2 | 24.4 | (15.4) | 45.2 | ||||
|
|
|||||||||
|
1 2019 includes results attributable to a noncontrolling interest in MP GOM, a Gulf of Mexico joint venture. |
|||||||||
|
MURPHY OIL CORPORATION |
|||||
|
PRODUCTION-RELATED EXPENSES |
|||||
|
(unaudited) |
|||||
|
(Dollars per barrel of oil equivalents sold) |
|||||
| Three Months Ended | |||||
| March 31, | |||||
| 2019 | 2018 | ||||
| Continuing operations | |||||
| United States – Eagle Ford Shale | |||||
| Lease operating expense | $ | 12.92 | 8.34 | ||
| Severance and ad valorem taxes | 3.03 | 3.01 | |||
| Depreciation, depletion and amortization (DD&A) expense | 23.90 | 24.84 | |||
| United States – Gulf of Mexico | |||||
| Lease operating expense | $ | 8.11 | 17.90 | ||
| DD&A expense | 14.39 | 17.35 | |||
| Canada – Onshore | |||||
| Lease operating expense | $ | 5.89 | 4.85 | ||
| Severance and ad valorem taxes | 0.06 | 0.10 | |||
| DD&A expense | 11.03 | 10.15 | |||
| Canada – Offshore | |||||
| Lease operating expense | $ | 17.43 | 10.96 | ||
| DD&A expense | 13.70 | 13.46 | |||
| Total oil and gas continuing operations | |||||
| Lease operating expense | $ | 8.93 | 8.43 | ||
| Severance and ad valorem taxes | 0.68 | 1.15 | |||
| DD&A expense | 15.78 | 16.90 | |||
| Total oil and gas continuing operations – excluding noncontrolling interest | |||||
| Lease operating expense | $ | 9.01 | 8.43 | ||
| Severance and ad valorem taxes | 0.75 | 1.15 | |||
| DD&A expense | 15.54 | 16.90 | |||
|
MURPHY OIL CORPORATION |
|||||
|
OTHER FINANCIAL DATA |
|||||
|
(unaudited) |
|||||
|
(Millions of dollars) |
|||||
| Three Months Ended | |||||
| March 31, | |||||
| 2019 | 2018 | ||||
| Capital expenditures for continuing operations | |||||
| Exploration and production | |||||
| United States | $ | 205.5 | 147.5 | ||
| Canada | 95.7 | 119.0 | |||
| Other | 41.3 | 9.7 | |||
| Total | 342.5 | 276.2 | |||
| Corporate | 4.1 | 5.1 | |||
| Total capital expenditures - continuing operations | 346.6 | 281.3 | |||
| Charged to exploration expenses 1 | |||||
| United States | 1.8 | 7.1 | |||
| Canada | 0.1 | 0.1 | |||
| Other | 22.6 | 8.3 | |||
| Total charged to exploration expenses - continuing operations | 24.5 | 15.5 | |||
| Total capitalized 2 | $ | 322.1 | 265.8 | ||
| Memo: Capital expenditures (including exploration) on discontinued operations | 21.9 | 19.1 | |||
|
1 Excludes amortization of undeveloped leases of $8.0 million and $13.2 million for the three months ended March 31, 2019 and 2018, respectively. |
|||||
|
2 Includes noncontrolling interest capital expenditures of $13.1 million. |
|||||
| MURPHY OIL CORPORATION | ||||||
| CONDENSED BALANCE SHEETS (unaudited) | ||||||
| (Millions of dollars) | ||||||
| March 31, 2019 | December 31, 2018 1 | |||||
|
Assets |
||||||
| Cash and cash equivalents | $ | 286.3 | 359.9 | |||
| Other current assets 2 | 2,352.0 | 520.0 | ||||
| Property, plant and equipment – net | 8,559.1 | 8,432.1 | ||||
| Other long-term assets | 785.7 | 1,740.6 | ||||
| Total assets | $ | 11,983.1 | 11,052.6 | |||
|
Liabilities and Stockholders' Equity |
||||||
| Current maturities of long-term debt | $ | 0.7 | 0.7 | |||
| Other current liabilities 2 | 1,637.5 | 845.4 | ||||
| Long-term debt | 3,110.1 | 3,109.3 | ||||
| Other long-term liabilities | 1,908.1 | 1,899.6 | ||||
| Total equity 3 | 5,326.7 | 5,197.6 | ||||
| Total liabilities and stockholders' equity | $ | 11,983.1 | 11,052.6 | |||
|
1 Reclassified to conform to current presentation. |
||||||
|
2 Includes $1,861.2 million and $819.4 million in 2019 in Other current assets and Other current liabilities, respectively, classified as held for sale related to Malaysia. |
||||||
|
3 Includes noncontrolling interest of $377.9 million and $368.3 million as of March 31, 2019 and December 31, 2018, respectively. |
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|
MURPHY OIL CORPORATION |
||||||||
|
PRODUCTION SUMMARY |
||||||||
|
(unaudited) |
||||||||
| Three Months Ended | ||||||||
| March 31, | ||||||||
|
Barrels per day unless otherwise noted |
2019 | 2018 | ||||||
| Continuing operations | ||||||||
| Net crude oil and condensate | ||||||||
| United States | Onshore | 25,880 | 31,553 | |||||
| Gulf of Mexico 1 | 61,048 | 12,615 | ||||||
| Canada | Onshore | 6,457 | 4,358 | |||||
| Offshore | 7,928 | 8,189 | ||||||
| Other | 507 | 585 | ||||||
| Total net crude oil and condensate - continuing operations | 101,820 | 57,300 | ||||||
| Net natural gas liquids | ||||||||
| United States | Onshore | 5,301 | 6,745 | |||||
| Gulf of Mexico 1 | 2,760 | 808 | ||||||
| Canada | Onshore | 1,093 | 884 | |||||
| Total net natural gas liquids - continuing operations | 9,154 | 8,437 | ||||||
| Net natural gas – thousands of cubic feet per day | ||||||||
| United States | Onshore | 29,279 | 31,233 | |||||
| Gulf of Mexico 1 | 19,575 | 12,670 | ||||||
| Canada | Onshore | 254,904 | 261,305 | |||||
| Total net natural gas - continuing operations | 303,758 | 305,208 | ||||||
| Total net hydrocarbons - continuing operations including NCI 2,3 | 161,600 | 116,605 | ||||||
| Noncontrolling interest | ||||||||
| Net crude oil and condensate – barrels per day | (12,185) | – | ||||||
| Net natural gas liquids – barrels per day | (554) | – | ||||||
| Net natural gas – thousands of cubic feet per day | (3,895) | – | ||||||
|
Total noncontrolling interest |
(13,388) | – | ||||||
| Total net hydrocarbons - continuing operations excluding NCI 2,3 | 148,212 | 116,605 | ||||||
| Discontinued operations | ||||||||
| Net crude oil and condensate – barrels per day | 25,954 | 31,233 | ||||||
| Net natural gas liquids – barrels per day | 744 | 455 | ||||||
| Net natural gas – thousands of cubic feet per day 2 | 101,592 | 115,276 | ||||||
| Total discontinued operations | 43,630 | 50,901 | ||||||
| Total net hydrocarbons produced excluding NCI 2,3 | 191,842 | 167,506 | ||||||
|
1 2019 includes net volumes attributable to a noncontrolling interest in MP GOM, a Gulf of Mexico joint venture. |
||||||||
|
2 Natural gas converted on an energy equivalent basis of 6:1. |
||||||||
|
3 NCI – noncontrolling interest in MP GOM, a Gulf of Mexico joint venture. |
||||||||
|
MURPHY OIL CORPORATION |
||||||
|
SALES SUMMARY |
||||||
|
(unaudited) |
||||||
| Three Months Ended | ||||||
| March 31, | ||||||
|
Barrels per day unless otherwise noted |
2019 | 2018 | ||||
| Continuing operations | ||||||
| Net crude oil and condensate | ||||||
| United States | Onshore | 25,880 | 31,553 | |||
| Gulf of Mexico 1 | 63,289 | 12,615 | ||||
| Canada | Onshore | 6,457 | 4,358 | |||
| Offshore | 7,932 | 9,188 | ||||
| Other | 467 | – | ||||
| Total net crude oil and condensate - continuing operations | 104,025 | 57,714 | ||||
| Net natural gas liquids | ||||||
| United States | Onshore | 5,301 | 6,745 | |||
| Gulf of Mexico 1 | 2,760 | 808 | ||||
| Canada | Onshore | 1,093 | 884 | |||
| Total net natural gas liquids - continuing operations | 9,154 | 8,437 | ||||
| Net natural gas sold – thousands of cubic feet per day | ||||||
| United States | Onshore | 29,279 | 31,233 | |||
| Gulf of Mexico 1 | 19,575 | 12,670 | ||||
| Canada | Onshore | 254,904 | 261,305 | |||
| Total net natural gas - continuing operations | 303,758 | 305,208 | ||||
| Total net hydrocarbons - continuing operations including NCI 2,3 | 163,805 | 117,019 | ||||
| Noncontrolling interest | ||||||
| Net crude oil and condensate – barrels per day | (12,633) | – | ||||
| Net natural gas liquids – barrels per day | (554) | – | ||||
| Net natural gas – thousands of cubic feet per day 2 | (3,895) | – | ||||
| Total noncontrolling interest | (13,836) | – | ||||
| Total net hydrocarbons - continuing operations excluding NCI 2,3 | 149,969 | 117,019 | ||||
| Discontinued operations | ||||||
| Net crude oil and condensate – barrels per day | 26,260 | 29,954 | ||||
| Net natural gas liquids – barrels per day | 663 | 966 | ||||
|
Net natural gas – thousands of cubic feet per day 2 |
101,592 | 115,276 | ||||
| Total discontinued operations | 43,855 | 50,133 | ||||
| Total net hydrocarbons sold excluding NCI 2,3 | 193,824 | 167,152 | ||||
|
1 2019 includes net volumes attributable to a noncontrolling interest in MP GOM, a Gulf of Mexico joint venture. |
||||||
|
2 Natural gas converted on an energy equivalent basis of 6:1. |
||||||
|
3 NCI – noncontrolling interest in MP GOM, a Gulf of Mexico joint venture. |
||||||
|
MURPHY OIL CORPORATION |
|||||||
|
PRICE SUMMARY |
|||||||
|
(unaudited) |
|||||||
| Three Months Ended | |||||||
| March 31, | |||||||
| 2019 | 2018 | ||||||
| Weighted average Exploration and Production sales prices | |||||||
| Continuing operations | |||||||
| Crude oil and condensate – dollars per barrel | |||||||
| United States | Onshore | $ | 57.36 | 64.28 | |||
| Gulf of Mexico 1 | 55.48 | 63.00 | |||||
| Canada 2 | Onshore | 47.06 | 54.29 | ||||
| Offshore | 61.42 | 65.69 | |||||
| Other | 67.90 | – | |||||
| Natural gas liquids – dollars per barrel | |||||||
| United States | Onshore | 12.89 | 19.93 | ||||
| Gulf of Mexico 1 | 16.81 | 22.57 | |||||
| Canada 2 | Onshore | 35.16 | 43.58 | ||||
| Natural gas – dollars per thousand cubic feet | |||||||
| United States | Onshore | 2.22 | 2.40 | ||||
| Gulf of Mexico 1 | 1.42 | 2.58 | |||||
| Canada 2 | Onshore | 1.95 | 1.68 | ||||
| Discontinued operations | |||||||
| Crude oil and condensate – dollars per barrel | |||||||
| Malaysia 3 | Sarawak | 62.70 | 64.48 | ||||
| Block K | 65.40 | 63.18 | |||||
| Natural gas liquids – dollars per barrel | |||||||
| Malaysia 3 | Sarawak | 52.44 | 71.21 | ||||
| Natural gas – dollars per thousand cubic feet | |||||||
| Malaysia 3 | Sarawak | 4.54 | 3.37 | ||||
| Block K | 0.24 | 0.22 | |||||
|
1 Prices include noncontrolling interest for MP GOM, a U.S. Gulf of Mexico joint venture. |
|||||||
|
2 U.S. dollar equivalent. |
|||||||
|
3 Prices are net of payments under the terms of the respective production sharing contracts. |
|||||||
| MURPHY OIL CORPORATION | ||||||||||||
| COMMODITY HEDGE POSITIONS (unaudited) | ||||||||||||
| AS OF APRIL 30, 2019 | ||||||||||||
| Volumes | Price | Remaining Period | ||||||||||
| Area | Commodity | Type | (Bbl/d) | (USD/Bbl) | Start Date | End Date | ||||||
|
United States |
WTI | Fixed price derivative swap | 20,000 | $63.64 | 5/1/2019 | 12/31/2019 | ||||||
|
United States |
WTI | Fixed price derivative swap | 20,000 | $60.10 | 1/1/2020 | 12/31/2020 | ||||||
| Volumes | Price | Remaining Period | ||||||||||
| Area | Commodity | Type | (MMcf/d) | (CAD/Mcf) | Start Date | End Date | ||||||
| Montney | Natural Gas |
Fixed price forward sales at AECO |
59 | C$2.81 | 4/1/2019 | 12/31/2020 | ||||||
| MURPHY OIL CORPORATION | ||||||
| SECOND QUARTER 2019 GUIDANCE | ||||||
| Liquids | Gas | |||||
| BOPD | MCFD | BOEPD | ||||
| Production – net | ||||||
|
U.S. – Eagle Ford Shale |
38,800 | 35,000 | 44,600 | |||
| – Gulf of Mexico including NCI 1 | 55,875 | 24,125 | 59,900 | |||
| – Gulf of Mexico excluding NCI | 44,700 | 19,300 | 47,900 | |||
| Canada – Tupper Montney | - | 206,700 | 34,500 | |||
| – Kaybob Duvernay and Placid Montney | 5,700 | 25,900 | 10,000 | |||
| – Offshore | 7,500 |
- |
7,500 | |||
|
Other |
500 |
- |
500 | |||
| Total net production (BOEPD) - including NCI 1 | 155,000 to 159,000 | |||||
| Total net production (BOEPD) - excluding NCI | 143,000 to 147,000 | |||||
| Total net sales (BOEPD) - including NCI | 154,500 to 158,500 | |||||
| Total net sales (BOEPD) - excluding NCI | 142,500 to 146,500 | |||||
| Exploration expense ($ millions) | $34 | |||||
| 1 Includes noncontrolling interest of MP GOM of 11,175 BOPD liquids and 4,825 MCFD gas. | ||||||
| FULL YEAR 2019 GUIDANCE 2 | ||||||
|
Capital expenditures - excluding NCI ($ billions) |
$1.15 - $1.35 | |||||
| 2 Full year production guidance will be updated upon completion of the previously announced business disposition and acquisition. | ||||||
