Executed Agreements to Divest Malaysia
Assets for $2.127 Billion, and Subsequent to Quarter End, Acquire
Gulf of Mexico Assets for $1.375 Billion
Drilled Discovery Wells in Mexico and
Vietnam
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(Bbl/d)
Price(USD/Bbl)
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 $60.10 Jan. 1, 2020 Dec. 31, 2020
Currently, Murphy has the following natural gas fixed price
forward sales as detailed in the table below.
Fixed Price Sales Open Positions, as of April 30, 2019
Remaining Period Area Commodity
Type
Volume(MMcf/d)
Price(CAD$/Mcf)
Start Date End Date Montney
Natural Gas
Fixed Price ForwardSales at AECO
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.
MURPHY OIL CORPORATION
SUMMARIZED CONSOLIDATED STATEMENTS OF
OPERATIONS (unaudited)
(Thousands of dollars, except per share
amounts)
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
Less: Net income attributable to
noncontrolling interest
32,587 -
NET INCOME ATTRIBUTABLE TO
MURPHY $ 40,182 168,253
INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations $ (0.06 ) 0.52 Discontinued operations
0.29 0.45 Net Income $ 0.23 0.97
INCOME (LOSS) PER COMMON SHARE –
DILUTED
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
1 Reclassified to conform to current
presentation.
MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
Three Months Ended March 31, 2019
2018 1
Operating Activities Net income including noncontrolling
interest $ 72,769 168,253
Adjustments to reconcile net income to net
cash provided by continuing operations activities:
(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
)
Net cash provided by continuing operations activities
217,197
110,887
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
Investing activities (26,438 ) (26,848 ) Financing activities
(2,547 ) (2,405 )
Net cash provided by discontinued
operations
94,484
138,133
Cash transferred from discontinued
operations to continuing operations
46,080
371,656
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
1 Reclassified to conform to current
presentation.
MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED INCOME (LOSS)
(unaudited)
(Millions of dollars, except per share
amounts)
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 )
(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 EndedMarch 31, 2019
Three Months EndedMarch 31, 2018
Revenues
Income(Loss)
Revenues
Income(Loss)
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.
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.
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.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20190502005391/en/
Kelly Whitley, kelly_whitley@murphyoilcorp.com,
281-675-9107Bryan Arciero, bryan_arciero@murphyoilcorp.com,
832-319-5374
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