Exceeded Upper End of Guidance Range With
Production of 184 MBOEPD, Signed Production Sharing
Contracts for Côte d’Ivoire New Country Entry, Executed
Agreement to Divest Non-Core Canadian Assets
Murphy Oil Corporation (NYSE: MUR) today announced its financial
and operating results for the second quarter ended June 30, 2023,
including net income attributable to Murphy of $98 million, or
$0.62 net income per diluted share. Excluding discontinued
operations and other items affecting comparability between periods,
adjusted net income attributable to Murphy was $124 million, or
$0.79 adjusted net income per diluted share.
Unless otherwise noted, the financial and operating highlights
and metrics discussed in this news release exclude noncontrolling
interest (NCI). 1
Highlights for the second quarter include:
- Exceeded upper end of guidance range with production of 184
thousand barrels of oil equivalent per day (MBOEPD), including 99
thousand barrels of oil per day (MBOPD)
- Received government approval on Block 15-1/05 Lac Da Vang field
development plan in Vietnam
- Signed production sharing contracts (PSCs) for five blocks
offshore Côte d’Ivoire
Subsequent to the second quarter:
- Signed a Purchase and Sale Agreement to divest a portion of
Kaybob Duvernay and Placid Montney assets for C$150 million net
purchase price
- Published the fifth annual Sustainability Report with enhanced
disclosures on improved environmental activities, increased
community support and continuing strong governance oversight
“Murphy’s operational excellence continues to shine as our
portfolio again outperformed expectations this quarter. From
offshore maintenance being completed faster than scheduled to
onshore wells achieving production rates above type curves, our
team has done a great job executing our 2023 plan. We also have
exciting opportunities ahead, including advancing the Vietnam Lac
Da Vang field development plan towards project sanction as well as
evaluating our new Côte d’Ivoire acreage. I look forward to
progressing our capital allocation framework this year with
increasing returns to shareholders and additional debt reduction,
which will be supported by monetizing a non-core portion of our
Canadian assets,” said Roger W. Jenkins, President and Chief
Executive Officer. “Additionally, Murphy continues to operate
sustainably, and we were recently recognized by Rystad Energy as
the highest-scoring company in ESG performance for the 2021
reporting year across 41 operators in the United States and
Canada.”
SECOND QUARTER 2023 RESULTS
The company recorded net income attributable to Murphy of $98
million, or $0.62 net income per diluted share, for the second
quarter 2023. Adjusted net income, which excludes both the results
of discontinued operations and certain other items that affect
comparability of results between periods, was $124 million, or
$0.79 adjusted net income per diluted share for the same period.
Adjustments to net income total $28 million before tax. Details for
second quarter results and an adjusted net income reconciliation
can be found in the attached schedules.
Including NCI, second quarter 2023 exploration expense of $116
million contains three primary items: $80 million of dry hole
expense for the Chinook #7 exploration well in the Gulf of Mexico,
inclusive of $26 million attributable to NCI; a $17 million
write-off of the previously suspended Cholula-1EXP exploration well
in offshore Mexico; and $10 million in seismic costs for the Côte
d’Ivoire new country entry.
Earnings before interest, taxes, depreciation and amortization
(EBITDA) attributable to Murphy were $373 million. Earnings before
interest, tax, depreciation, amortization and exploration expenses
(EBITDAX) attributable to Murphy were $463 million. Adjusted EBITDA
attributable to Murphy was $412 million. Adjusted EBITDAX
attributable to Murphy was $485 million. Reconciliations for second
quarter EBITDA, EBITDAX, adjusted EBITDA and adjusted EBITDAX can
be found in the attached schedules.
In the second quarter, Murphy paid the final contingent
consideration payments of $28 million related to the Gulf of Mexico
acquisition that closed in 2019. This amount was primarily
attributable to the one-year anniversary of achieving first oil at
King’s Quay. Murphy has no remaining contingent consideration
payment obligations.
Second quarter production averaged 184 MBOEPD and consisted of
54 percent oil volumes, or 99 MBOPD. Production for the quarter
exceeded the upper end of the guidance range, primarily driven by
2.5 MBOEPD of strong well performance in the Gulf of Mexico, 2.1
MBOEPD in the Tupper Montney and 1.5 MBOEPD in the Eagle Ford
Shale, as well as 1.4 MBOEPD attributed to lower realized royalty
rates in the Tupper Montney natural gas asset. Details for second
quarter production can be found in the attached schedules.
FINANCIAL POSITION
Murphy had approximately $1.1 billion of liquidity on June 30,
2023, with no borrowings on the $800 million credit facility and
$369 million of cash and cash equivalents, inclusive of NCI.
On June 30, 2023, the company’s total debt was unchanged from
year-end 2022 at $1.82 billion, and consisted of long-term,
fixed-rate notes with a weighted average maturity of 7.2 years and
a weighted average coupon of 6.1 percent.
CANADA TRANSACTION SUMMARY
Subsequent to quarter end, a subsidiary of Murphy signed a
Purchase and Sale Agreement to divest a non-core portion of its
operated Kaybob Duvernay assets and all of its non-operated Placid
Montney assets to a private company. Under the terms of the
agreement, the buyer will pay Murphy C$150 million at closing in an
all-cash transaction, subject to customary closing adjustments and
conditions. The transaction has a March 1, 2023 effective date,
with closing anticipated to occur in the third quarter of 2023.
The assets to be divested include the Saxon and Simonette areas
of the Kaybob Duvernay, where Murphy holds a 70 percent working
interest as operator, as well as Murphy’s 30 percent working
interest in the Placid Montney assets operated by Athabasca Oil
Corporation. Also included are batteries, pipelines and the
assumption of related processing and marketing contracts.
The combined assets currently produce approximately 1,700
barrels of oil equivalent per day (BOEPD) net and are comprised of
39 percent oil. Net proved reserves are 5.3 million barrels of oil
equivalent (MMBOE) as of December 31, 2022. Also included are 250
gross drilling locations, or 138 net, across 42,000 net acres in
Kaybob Duvernay and 26,000 net acres in Placid Montney. After the
transaction closes, Murphy will have approximately 488 gross
drilling locations with an average 75 percent oil weighting
remaining in the Kaybob Duvernay, all of which are operated with a
70 percent working interest. Murphy will have no remaining position
in the Placid Montney.
“This transaction brings forward the value of a small, non-core
portion of our onshore Canadian portfolio, as we were not planning
to develop these locations for many years. I look forward to
progressing our capital allocation framework goals in Murphy 2.0
with the proceeds from this divestiture, and continuing to reward
our supportive, long-term shareholders in the upcoming quarters,”
said Jenkins.
OPERATIONS SUMMARY
Onshore
In the second quarter of 2023, the onshore business produced
approximately 98 MBOEPD, which included 36 percent liquids
volumes.
Eagle Ford Shale – Production averaged 35 MBOEPD with 76
percent oil volumes and 89 percent liquids volumes. As planned,
during the second quarter Murphy brought nine Catarina and eight
Tilden operated wells online. Murphy continues to see stronger
performance from completion design improvements across its well
locations, including promising results in its new Tilden wells with
an average gross 30-day (IP30) rate of approximately 1,200 BOEPD
with 85 percent oil.
Tupper Montney – Natural gas production averaged 341
million cubic feet per day (MMCFD) in the second quarter, with 10
operated wells brought online. Of those wells, seven were brought
on early that were originally planned for the third quarter.
Production for the quarter exceeded guidance by 21 MMCFD, which
included 13 MMCFD of improved well performance as Murphy realized
its highest initial production rates in Tupper Montney history, as
well as an 8 MMCFD benefit from a lower realized royalty rate of
2.4 percent.
“Our new onshore well completion design, developed within the
last three years, is paying off with higher initial production
rates,” said Jenkins. “With this new design, we have achieved
continued exceptional results from new wells in both our Eagle Ford
Shale and Tupper Montney assets.”
Kaybob Duvernay – During the second quarter, production
averaged 4 MBOEPD with 60 percent liquids volumes. Production was
minimally impacted from wildfires during the quarter, and no damage
was sustained to facilities.
Offshore
Excluding NCI, the offshore business produced approximately 87
MBOEPD for the second quarter, which included 80 percent oil.
Gulf of Mexico – Production averaged approximately 84
MBOEPD, consisting of 79 percent oil during the second quarter.
Facility maintenance was completed as planned during the quarter,
with work at King’s Quay concluded ahead of schedule.
Canada – In the second quarter, production averaged 3
MBOEPD, consisting of 100 percent oil. The asset life extension
project is progressing for the non-operated Terra Nova floating,
production, storage and offloading vessel, which Murphy anticipates
will return to production by year-end 2023.
Vietnam – As previously disclosed, during the second
quarter Murphy received government approval of the Block 15-1/05
Lac Da Vang field development plan in the Cuu Long Basin. Murphy
holds a 40 percent working interest as operator of the block.
PetroVietnam Exploration Production Corporation Limited and SK
Earthon Co., Ltd. hold the remaining 35 percent and 25 percent
working interest, respectively. Murphy is working to advance the
development project in preparation for final review and sanction in
late 2023.
EXPLORATION
Côte d’Ivoire – During the second quarter, Murphy signed
production sharing contracts to secure working interests as
operator in five deepwater blocks in the Tano Basin offshore Côte
d’Ivoire. Murphy will initially hold a 90 percent working interest
in four blocks, with an 85 percent working interest in the fifth
block. Société Nationale d’Opérations Pétrolières de la Côte
d’Ivoire (PETROCI) holds the remaining working interest for each
block.
Included in Block CI-103 is the Paon discovery, which was
appraised with multiple wells by a previous operator. The PSC for
the block includes a commitment to formulate and submit a viable
field development plan for this discovery by the end of 2025.
“We are excited for our new country entry as an operator in Côte
d’Ivoire, and are pleased with the competitive terms and low entry
cost,” said Jenkins. “These blocks offer tremendous opportunities
for exploration, and we look forward to maturing geophysical
studies in this area and working with PETROCI on the possible
development of the Paon discovery.”
Gulf of Mexico – Following the quarter, Murphy, as
operator of its subsidiary MP Gulf of Mexico, LLC, concluded
drilling the Chinook #7 exploration well in Walker Ridge 425. The
well encountered non-commercial hydrocarbons. Murphy plugged and
abandoned the well, and approximately $80 million of the well cost
before tax, inclusive of $26 million attributable to NCI, was
expensed in the second quarter. Murphy holds a 66.66 percent
working interest in the well.
As previously announced, during the second quarter Murphy, as
operator, drilled a discovery at the Longclaw #1 exploration well.
The company holds a 14.5 percent working interest in the well. The
well reached a total measured depth of 25,106 feet at a net cost of
approximately $6 million. The well encountered approximately 62
feet of net oil pay and is undergoing further evaluation.
Also during the quarter, Murphy was awarded five exploration
blocks from the Gulf of Mexico Federal Lease Sale 259 with an
average working interest of 90 percent.
Mexico – In conjunction with the July 2023 expiration of
the Cholula appraisal period, Murphy wrote off previously suspended
exploration well costs of $17 million.
2023 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE
Second quarter accrued capital expenditures (CAPEX) of $300
million, excluding lease acquisition costs, was lower than guidance
due to timing of non-operated activity. Murphy accrued a total of
$32 million in acquisition-related costs during the quarter, which
will be paid in third quarter 2023.
Murphy is tightening its 2023 accrued CAPEX range to $950
million to $1.025 billion, which excludes $45 million in
acquisition-related CAPEX for Côte d’Ivoire and Vietnam.
The company is raising its full year 2023 production range of
180 to 186 MBOEPD, consisting of approximately 53 percent oil and
59 percent liquids volumes.
Production for third quarter 2023 is estimated to be in the
range of 188 to 196 MBOEPD with 99 MBOPD, or 52 percent, oil
volumes. This range includes assumed Gulf of Mexico storm downtime
of 4.6 MBOEPD, as well as operated planned downtime of 2.3 MBOEPD
onshore and 600 BOEPD offshore. Murphy forecasts third quarter
accrued CAPEX of $215 million, excluding acquisition-related
costs.
Both production and CAPEX guidance ranges exclude NCI.
Production guidance will be adjusted following closing of the
Canadian divestiture announced today.
Detailed guidance for the third quarter and full year 2023 is
contained in the attached schedules.
FIXED PRICE FORWARD SALES CONTRACTS
Murphy maintains fixed price forward sales contracts tied to
AECO pricing points to lessen its dependence on variable AECO
prices. These contracts are for physical delivery of natural gas
volumes at a fixed price, with no mark-to-market income
adjustments. Details for the current fixed price contracts can be
found in the attached schedules.
CONFERENCE CALL AND WEBCAST SCHEDULED FOR AUGUST 3,
2023
Murphy will host a conference call to discuss second quarter
2023 financial and operating results on Thursday, August 3, 2023,
at 9:00 a.m. EDT. The call can be accessed either via the Internet
through the Investor Relations section of Murphy Oil’s website at
http://ir.murphyoilcorp.com or via the telephone by dialing toll
free 1-888-886-7786, reservation number 24655854.
FINANCIAL DATA
Summary financial data and operating statistics for second
quarter 2023, with comparisons to the same period from the previous
year, are contained in the following schedules. Additionally, a
schedule indicating the impacts of items affecting comparability of
results between periods, a reconciliation of EBITDA, EBITDAX,
adjusted EBITDA and adjusted EBITDAX between periods, as well as
guidance for the third quarter and full year 2023, are also
included.
1In accordance with GAAP, Murphy reports the 100 percent
interest, including a 20 percent noncontrolling interest (NCI), in
its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP
financials include the NCI portion of revenue, costs, assets and
liabilities and cash flows. Unless otherwise noted, the financial
and operating highlights and metrics discussed in this news
release, but not the accompanying schedules, exclude the NCI,
thereby representing only the amounts attributable to Murphy.
CAPITAL ALLOCATION FRAMEWORK
This news release contains references to the company’s capital
allocation framework and adjusted free cash flow. As previously
disclosed, the capital allocation framework defines Murphy 1.0 as
when long-term debt exceeds $1.8 billion. At such time, adjusted
free cash flow is allocated to long-term debt reduction while the
company continues to support the quarterly dividend. The company
reaches Murphy 2.0 when long-term debt is between $1.0 billion and
$1.8 billion. At such time, approximately 75 percent of adjusted
free cash flow is allocated to debt reduction, with the remaining
25 percent distributed to shareholders through share buybacks and
potential dividend increases. When long-term debt is at or below
$1.0 billion, the company is in Murphy 3.0 and begins allocating 50
percent of adjusted free cash flow to the balance sheet, with a
minimum of 50 percent of adjusted free cash flow allocated to share
buybacks and potential dividend increases.
Adjusted free cash flow is defined as cash flow from operations
before working capital change, less capital expenditures,
distributions to NCI and projected payments, quarterly dividend and
accretive acquisitions.
ABOUT MURPHY OIL CORPORATION
As an independent oil and natural gas exploration and production
company, Murphy Oil Corporation believes in providing energy that
empowers people by doing right always, staying with it and thinking
beyond possible. Murphy challenges the norm, taps into its strong
legacy and uses its foresight and financial discipline to deliver
inspired energy solutions. Murphy sees a future where it is an
industry leader who is positively impacting lives for the next 100
years and beyond. Additional information can be found on the
company’s website at www.murphyoilcorp.com.
FORWARD-LOOKING STATEMENTS
This news release contains forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995.
Forward-looking statements are generally identified through the
inclusion of words such as “aim”, “anticipate”, “believe”, “drive”,
“estimate”, “expect”, “expressed confidence”, “forecast”, “future”,
“goal”, “guidance”, “intend”, “may”, “objective”, “outlook”,
“plan”, “position”, “potential”, “project”, “seek”, “should”,
“strategy”, “target”, “will” or variations of such words and other
similar expressions. These statements, which express management’s
current views concerning future events, results and plans, are
subject to inherent risks, uncertainties and assumptions (many of
which are beyond our control) and are not guarantees of
performance. In particular, statements, express or implied,
concerning the company’s future operating results or activities and
returns or the company's ability and decisions to replace or
increase reserves, increase production, generate returns and rates
of return, replace or increase drilling locations, reduce or
otherwise control operating costs and expenditures, generate cash
flows, pay down or refinance indebtedness, achieve, reach or
otherwise meet initiatives, plans, goals, ambitions or targets with
respect to emissions, safety matters or other ESG
(environmental/social/governance) matters, make capital
expenditures or pay and/or increase dividends or make share
repurchases and other capital allocation decisions are
forward-looking statements. Factors that could cause one or more of
these future events, results or plans not to occur as implied by
any forward-looking statement, which consequently could cause
actual results or activities to differ materially from the
expectations expressed or implied by such forward-looking
statements, include, but are not limited to: macro conditions in
the oil and gas industry, including supply/demand levels, actions
taken by major oil exporters and the resulting impacts on commodity
prices; increased volatility or deterioration in the success rate
of our exploration programs or in our ability to maintain
production rates and replace reserves; reduced customer demand for
our products due to environmental, regulatory, technological or
other reasons; adverse foreign exchange movements; political and
regulatory instability in the markets where we do business; the
impact on our operations or market of health pandemics such as
COVID-19 and related government responses; other natural hazards
impacting our operations or markets; any other deterioration in our
business, markets or prospects; any failure to obtain necessary
regulatory approvals; any inability to service or refinance our
outstanding debt or to access debt markets at acceptable prices; or
adverse developments in the U.S. or global capital markets, credit
markets, banking system or economies in general. For further
discussion of factors that could cause one or more of these future
events or results not to occur as implied by any forward-looking
statement, see “Risk Factors” in our most recent Annual Report on
Form 10-K filed with the U.S. Securities and Exchange Commission
(“SEC”) and any subsequent Quarterly Report on Form 10-Q or Current
Report on Form 8-K that we file, available from the SEC’s website
and from Murphy Oil Corporation’s website at
http://ir.murphyoilcorp.com. Investors and others should note that
we may announce material information using SEC filings, press
releases, public conference calls, webcasts and the investors page
of our website. We may use these channels to distribute material
information about the company; therefore, we encourage investors,
the media, business partners and others interested in the company
to review the information we post on our website. The information
on our website is not part of, and is not incorporated into, this
report. Murphy Oil Corporation undertakes no duty to publicly
update or revise any forward-looking statements.
NON-GAAP FINANCIAL MEASURES
This news release contains certain non-GAAP financial measures
that management believes are useful tools for internal use and the
investment community in evaluating Murphy Oil Corporation’s overall
financial performance. These non-GAAP financial measures are
broadly used to value and compare companies in the crude oil and
natural gas industry. Not all companies define these measures in
the same way. In addition, these non-GAAP financial measures are
not a substitute for financial measures prepared in accordance with
GAAP and should therefore be considered only as supplemental to
such GAAP financial measures. Please see the attached schedules for
reconciliations of the differences between the non-GAAP financial
measures used in this news release and the most directly comparable
GAAP financial measures.
MURPHY OIL CORPORATION
SUMMARIZED CONSOLIDATED
STATEMENTS OF OPERATIONS (unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Thousands of
dollars, except per share amounts)
2023
2022
2023
2022
Revenues and other income
Revenue from production
$
799,836
1,146,299
$
1,596,067
1,980,827
Sales of purchased natural gas
13,014
49,939
56,751
86,785
Total revenue from sales to customers
812,850
1,196,238
1,652,818
2,067,612
Loss on derivative instruments
—
(103,068
)
—
(423,845
)
Gain on sale of assets and other
income
1,738
7,887
3,486
10,251
Total revenues and other income
814,588
1,101,057
1,656,304
1,654,018
Costs and expenses
Lease operating expenses
194,292
147,352
394,276
284,177
Severance and ad valorem taxes
12,765
17,565
24,205
32,200
Transportation, gathering and
processing
59,868
49,948
113,790
96,871
Costs of purchased natural gas
9,657
47,971
41,926
81,636
Exploration expenses, including
undeveloped lease amortization
115,793
15,151
125,975
62,717
Selling and general expenses
25,345
27,130
43,653
60,659
Depreciation, depletion and
amortization
215,667
195,856
411,337
359,980
Accretion of asset retirement
obligations
11,364
11,563
22,521
23,439
Other operating expense
4,960
36,913
16,948
142,855
Total costs and expenses
649,711
549,449
1,194,631
1,144,534
Operating income from continuing
operations
164,877
551,608
461,673
509,484
Other income (loss)
Other (expenses) income
(7,694
)
5,308
(7,767
)
2,813
Interest expense, net
(29,856
)
(41,385
)
(58,711
)
(78,662
)
Total other loss
(37,550
)
(36,077
)
(66,478
)
(75,849
)
Income from continuing operations before
income taxes
127,327
515,531
395,195
433,635
Income tax expense
34,870
105,084
88,703
88,123
Income from continuing operations
92,457
410,447
306,492
345,512
Loss from discontinued operations, net of
income taxes
(602
)
(943
)
(323
)
(1,494
)
Net income including noncontrolling
interest
91,855
409,504
306,169
344,018
Less: Net (loss) income attributable to
noncontrolling interest
(6,431
)
58,947
16,239
106,797
NET INCOME ATTRIBUTABLE TO
MURPHY
$
98,286
350,557
$
289,930
237,221
INCOME (LOSS) PER COMMON SHARE –
BASIC
Continuing operations
$
0.63
2.27
$
1.86
1.54
Discontinued operations
—
(0.01
)
—
(0.01
)
Net income
$
0.63
2.26
$
1.86
1.53
INCOME (LOSS) PER COMMON SHARE –
DILUTED
Continuing operations
$
0.62
2.24
$
1.84
1.51
Discontinued operations
—
(0.01
)
—
(0.01
)
Net income
$
0.62
2.23
$
1.84
1.50
Cash dividends per common share
$
0.275
0.175
$
0.550
0.325
Average common shares outstanding
(thousands)
Basic
156,127
155,389
155,976
155,121
Diluted
157,299
157,455
157,308
157,852
MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH
FLOWS (unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Thousands of
dollars)
2023
2022
2023
2022
Operating Activities
Net income including noncontrolling
interest
$
91,855
409,504
$
306,169
344,018
Adjustments to reconcile net income to net
cash provided by continuing operations activities
Loss from discontinued operations
602
943
323
1,494
Depreciation, depletion and
amortization
215,667
195,856
411,337
359,980
Unsuccessful exploration well costs and
previously suspended exploration costs
95,682
1,271
96,533
34,102
Amortization of undeveloped leases
2,716
3,782
5,369
7,980
Accretion of asset retirement
obligations
11,364
11,563
22,521
23,439
Deferred income tax expense
43,515
86,944
92,557
66,691
Contingent consideration payment
(15,609
)
—
(139,574
)
—
Mark-to-market loss on contingent
consideration
3,175
31,692
7,113
129,818
Mark-to-market (gain) loss on derivative
instruments
—
(88,166
)
—
100,343
Long-term non-cash compensation
13,540
23,179
22,076
40,467
(Gain) from sale of assets
—
(35
)
—
(35
)
Net decrease (increase) in non-cash
working capital
59,691
(40,676
)
(15,340
)
(121,598
)
Other operating activities, net
(52,307
)
(14,946
)
(59,417
)
(27,458
)
Net cash provided by continuing operations
activities
469,891
620,911
749,667
959,241
Investing Activities
Property additions and dry hole costs
(349,434
)
(307,917
)
(694,753
)
(552,825
)
Acquisition of oil and natural gas
properties
—
(46,491
)
—
(46,491
)
Proceeds from sales of property, plant and
equipment
—
47
—
47
Net cash required by investing
activities
(349,434
)
(354,361
)
(694,753
)
(599,269
)
Financing Activities
Borrowings on revolving credit
facility
100,000
100,000
200,000
100,000
Repayment of revolving credit facility
(100,000
)
(100,000
)
(200,000
)
(100,000
)
Retirement of debt
—
(200,000
)
—
(200,000
)
Early redemption of debt cost
—
(3,438
)
—
(3,438
)
Distributions to noncontrolling
interest
(6,304
)
(54,970
)
(15,983
)
(94,854
)
Contingent consideration payment
(12,565
)
(26,573
)
(60,243
)
(81,742
)
Issue costs of debt facility
(3
)
—
(20
)
—
Cash dividends paid
(42,942
)
(27,191
)
(85,867
)
(50,491
)
Withholding tax on stock-based incentive
awards
(3
)
(1,276
)
(14,220
)
(16,697
)
Capital lease obligation payments
(157
)
(162
)
(296
)
(320
)
Net cash required by financing
activities
(61,974
)
(313,610
)
(176,629
)
(447,542
)
Effect of exchange rate changes on cash
and cash equivalents
(1,511
)
(1,508
)
(893
)
(1,595
)
Net increase (decrease) in cash and cash
equivalents
56,972
(48,568
)
(122,608
)
(89,165
)
Cash and cash equivalents at beginning of
period
312,383
480,587
491,963
521,184
Cash and cash equivalents at end of
period
$
369,355
432,019
$
369,355
432,019
MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED NET INCOME
(LOSS) (unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Millions of
dollars, except per share amounts)
2023
2022
2023
2022
Net income attributable to Murphy
(GAAP)
$
98.3
350.6
$
289.9
237.2
Discontinued operations loss
0.6
0.9
0.3
1.5
Net income (loss) from continuing
operations attributable to Murphy
98.9
351.5
290.2
238.7
Adjustments1:
Write-off of previously suspended
exploration well
17.1
—
17.1
—
Foreign exchange (gain) loss
7.9
(8.0
)
8.3
(8.0
)
Mark-to-market loss on contingent
consideration
3.2
31.7
7.1
129.8
Mark-to-market (gain) loss on derivative
instruments
—
(88.2
)
—
100.3
Early redemption of debt cost
—
4.4
—
4.4
Total adjustments, before taxes
28.2
(60.1
)
32.5
234.5
Income tax expense (benefit) related to
adjustments
2.7
(13.2
)
3.6
47.4
Total adjustments after taxes
25.5
(46.9
)
28.9
179.1
Adjusted net income from continuing
operations attributable to Murphy (Non-GAAP)
$
124.4
304.6
$
319.1
417.8
Adjusted net income from continuing
operations per average diluted share (Non-GAAP)
$
0.79
1.93
$
2.03
2.65
1 Certain prior-period amounts have been
updated to conform to the current period presentation.
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Adjusted
net income from continuing operations attributable to Murphy.
Adjusted net income excludes certain items that management believes
affect the comparability of results between periods. Management
believes this is important information to provide because it is
used by management to evaluate the Company’s operational
performance and trends between periods and relative to its industry
competitors. Management also believes this information may be
useful to investors and analysts to gain a better understanding of
the Company’s financial results. Adjusted net income is a non-GAAP
financial measure and should not be considered a substitute for Net
income as determined in accordance with accounting principles
generally accepted in the United States of America.
The pretax and income tax impacts for adjustments shown above
are as follows by area of operations and exclude the share
attributable to non-controlling interests.
Three Months Ended
June 30, 2023
Six Months Ended
June 30, 2023
(Millions of
dollars)
Pretax
Tax
Net
Pretax
Tax
Net
Exploration & Production:
United States
$
3.2
0.7
2.5
$
7.1
1.5
5.6
Other
17.1
—
17.1
17.1
—
17.1
Corporate
7.9
2.0
5.9
8.3
2.1
6.2
Total adjustments
$
28.2
2.7
25.5
$
32.5
3.6
28.9
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE
INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION (EBITDA)
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Millions of
dollars)
2023
2022
2023
2022
Net income attributable to Murphy
(GAAP)
$
98.3
350.6
$
289.9
237.2
Income tax expense
34.9
105.1
88.7
88.1
Interest expense, net
29.9
41.4
58.7
78.7
Depreciation, depletion and amortization
expense ¹
210.1
188.2
399.3
344.8
EBITDA attributable to Murphy
(Non-GAAP)
$
373.2
685.3
$
836.6
748.8
Write-off of previously suspended
exploration well
17.1
—
17.1
—
Accretion of asset retirement obligations
¹
10.1
10.2
20.0
20.7
Foreign exchange loss (gain)
7.9
(8.0
)
8.3
(8.0
)
Mark-to-market loss on contingent
consideration
3.2
31.7
7.1
129.8
Discontinued operations loss
0.6
0.9
0.3
1.5
Mark-to-market (gain) loss on derivative
instruments
—
(88.1
)
—
100.4
Adjusted EBITDA attributable to Murphy
(Non-GAAP)
$
412.1
632.0
$
889.4
993.2
1 Depreciation, depletion, and
amortization expense, and accretion of asset retirement obligations
used in the computation of Adjusted EBITDA exclude the portion
attributable to the non-controlling interest (NCI).
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Earnings
before interest, taxes, depreciation and amortization (EBITDA) and
adjusted EBITDA. Management believes EBITDA and adjusted EBITDA are
important information to provide because they are used by
management to evaluate the Company’s operational performance and
trends between periods and relative to its industry competitors.
Management also believes this information may be useful to
investors and analysts to gain a better understanding of the
Company’s financial results. EBITDA and adjusted EBITDA are
non-GAAP financial measures and should not be considered a
substitute for Net income or Cash provided by operating activities
as determined in accordance with accounting principles generally
accepted in the United States of America.
MURPHY OIL CORPORATION
SCHEDULE OF EARNINGS BEFORE
INTEREST, TAXES, DEPRECIATION
AND AMORTIZATION AND EXPLORATION
(EBITDAX)
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Millions of
dollars)
2023
2022
2023
2022
Net income attributable to Murphy
(GAAP)
$
98.3
350.6
$
289.9
237.2
Income tax expense
34.9
105.1
88.7
88.1
Interest expense, net
29.9
41.4
58.7
78.7
Depreciation, depletion and amortization
expense ¹
210.1
188.2
399.3
344.8
EBITDA attributable to Murphy
(Non-GAAP)
373.2
685.3
836.6
748.8
Exploration expenses 1
89.5
15.2
99.7
62.7
EBITDAX attributable to Murphy
(Non-GAAP)
462.7
700.5
936.3
811.5
Accretion of asset retirement obligations
¹
10.1
10.2
20.0
20.7
Foreign exchange loss (gain)
7.9
(8.0
)
8.3
(8.0
)
Mark-to-market loss on contingent
consideration
3.2
31.7
7.1
129.8
Discontinued operations loss
0.6
0.9
0.3
1.5
Mark-to-market (gain) loss on derivative
instruments
—
(88.1
)
—
100.4
Adjusted EBITDAX attributable to Murphy
(Non-GAAP)
$
484.5
$
647.2
$
972.0
$
1,055.9
1 Depreciation, depletion, and
amortization expense, accretion of asset retirement obligations and
exploration expenses used in the computation of adjusted EBITDAX
exclude the portion attributable to the non-controlling interest
(NCI).
Non-GAAP Financial Measures
Presented above is a reconciliation of Net income to Earnings
before interest, taxes, depreciation and amortization, and
exploration expenses (EBITDAX) and adjusted EBITDAX. Management
believes EBITDAX and adjusted EBITDAX are important information to
provide because they are used by management to evaluate the
Company’s operational performance and trends between periods and
relative to its industry competitors. Management also believes this
information may be useful to investors and analysts to gain a
better understanding of the Company’s financial results. EBITDAX
and adjusted EBITDAX are non-GAAP financial measures and should not
be considered a substitute for Net income or Cash provided by
operating activities as determined in accordance with accounting
principles generally accepted in the United States of America.
MURPHY OIL CORPORATION
FUNCTIONAL RESULTS OF OPERATIONS
(unaudited)
Three Months Ended
June 30, 2023
Three Months Ended
June 30, 2022
(Millions of dollars)
Revenues
Income
(Loss)
Revenues
Income
(Loss)
Exploration and production
United States 1
$
696.2
168.9
$
978.0
491.5
Canada
118.3
2.5
206.6
47.2
Other
—
(32.3
)
13.7
(3.5
)
Total exploration and production
814.5
139.1
1,198.3
535.2
Corporate
0.1
(46.6
)
(97.2
)
(124.8
)
Continuing operations
814.6
92.5
1,101.1
410.4
Discontinued operations, net of tax
—
(0.6
)
—
(0.9
)
Total including noncontrolling
interest
$
814.6
91.9
$
1,101.1
409.5
Net income attributable to Murphy
98.3
350.6
Six Months Ended
June 30, 2023
Six Months Ended
June 30, 2022
(Millions of dollars)
Revenues
Income
(Loss)
Revenues
Income
(Loss)
Exploration and production
United States 1
$
1,378.5
394.9
$
1,685.4
744.4
Canada
274.1
24.4
372.7
69.9
Other
3.6
(37.6
)
13.7
(47.7
)
Total exploration and production
1,656.2
381.7
2,071.8
766.6
Corporate
0.1
(75.2
)
(417.8
)
(421.1
)
Continuing operations
1,656.3
306.5
1,654.0
345.5
Discontinued operations, net of tax
—
(0.3
)
—
(1.5
)
Total including noncontrolling
interest
$
1,656.3
306.2
$
1,654.0
344.0
Net income attributable to Murphy
289.9
237.2
1 Includes results attributable to a
noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS
(unaudited)
THREE MONTHS ENDED JUNE 30, 2023,
AND 2022
(Millions of
dollars)
United
States 1
Canada
Other
Total
Three Months Ended June 30,
2023
Oil and gas sales and other operating
revenues
$
696.2
105.3
—
801.5
Sales of purchased natural gas
—
13.0
—
13.0
Lease operating expenses
156.5
37.5
0.1
194.1
Severance and ad valorem taxes
12.4
0.4
—
12.8
Transportation, gathering and
processing
39.9
20.1
—
60.0
Costs of purchased natural gas
—
9.7
—
9.7
Depreciation, depletion and
amortization
178.0
35.0
—
213.0
Accretion of asset retirement
obligations
9.3
1.9
0.1
11.3
Exploration expenses
Dry holes and previously suspended
exploration costs
79.8
—
15.8
95.6
Geological and geophysical
0.4
0.1
10.0
10.5
Other exploration
1.7
—
5.3
7.0
81.9
0.1
31.1
113.1
Undeveloped lease amortization
2.1
—
0.6
2.7
Total exploration expenses
84.0
0.1
31.7
115.8
Selling and general expenses
(1.9
)
4.7
2.6
5.4
Other
0.5
5.4
1.4
7.3
Results of operations before taxes
217.5
3.5
(35.9
)
185.1
Income tax provisions (benefits)
48.6
1.0
(3.6
)
46.0
Results of operations (excluding Corporate
segment)
$
168.9
2.5
(32.3
)
139.1
Three Months Ended June 30,
2022
Oil and gas sales and other operating
revenues
$
977.8
156.8
13.7
1,148.3
Sales of purchased natural gas
0.2
49.8
—
50.0
Lease operating expenses
109.5
36.9
0.9
147.3
Severance and ad valorem taxes
17.3
0.3
—
17.6
Transportation, gathering and
processing
32.3
17.6
—
49.9
Costs of purchased natural gas
0.2
47.7
—
47.9
Depreciation, depletion and
amortization
153.7
35.6
3.4
192.7
Accretion of asset retirement
obligations
9.1
2.4
0.1
11.6
Exploration expenses
Dry holes and previously suspended
exploration costs
(0.7
)
—
2.0
1.3
Geological and geophysical
—
0.1
0.8
0.9
Other exploration
2.9
0.3
6.0
9.2
2.2
0.4
8.8
11.4
Undeveloped lease amortization
2.3
—
1.4
3.7
Total exploration expenses
4.5
0.4
10.2
15.1
Selling and general expenses
3.2
3.8
2.1
9.1
Other
35.3
(2.3
)
—
33.0
Results of operations before taxes
612.9
64.2
(3.0
)
674.1
Income tax provisions
121.4
17.0
0.5
138.9
Results of operations (excluding Corporate
segment)
$
491.5
47.2
(3.5
)
535.2
1 Includes results attributable to a
noncontrolling interest in MP GOM.
MURPHY OIL CORPORATION
OIL AND GAS OPERATING RESULTS
(unaudited)
SIX MONTHS ENDED JUNE 30, 2023,
AND 2022
(Millions of
dollars)
United
States 1
Canada
Other
Total
Six Months Ended June 30, 2023
Oil and gas sales and other operating
revenues
$
1,378.5
217.2
3.6
1,599.3
Sales of purchased natural gas
—
56.8
—
56.8
Lease operating expenses
319.2
74.3
0.7
394.2
Severance and ad valorem taxes
23.5
0.7
—
24.2
Transportation, gathering and
processing
77.3
36.5
—
113.8
Costs of purchased natural gas
—
41.9
—
41.9
Depreciation, depletion and
amortization
338.2
66.7
0.9
405.8
Accretion of asset retirement
obligations
18.4
3.9
0.2
22.5
Exploration expenses
Dry holes and previously suspended
exploration costs
79.6
—
16.9
96.5
Geological and geophysical
0.7
0.1
10.5
11.3
Other exploration
3.3
0.1
9.4
12.8
83.6
0.2
36.8
120.6
Undeveloped lease amortization
4.1
0.1
1.2
5.4
Total exploration expenses
87.7
0.3
38.0
126.0
Selling and general expenses
4.5
7.1
2.8
14.4
Other
9.9
9.7
1.4
21.0
Results of operations before taxes
499.8
32.9
(40.4
)
492.3
Income tax provisions (benefits)
104.9
8.5
(2.8
)
110.6
Results of operations (excluding Corporate
segment)
$
394.9
24.4
(37.6
)
381.7
Six Months Ended June 30, 2022
Oil and gas sales and other operating
revenues
$
1,685.2
286.1
13.7
1,985.0
Sales of purchased natural gas
0.2
86.6
—
86.8
Lease operating expenses
209.4
73.8
0.9
284.1
Severance and ad valorem taxes
31.5
0.7
—
32.2
Transportation, gathering and
processing
61.5
35.3
—
96.8
Costs of purchased natural gas
0.2
81.6
—
81.8
Depreciation, depletion and
amortization
280.2
69.8
3.5
353.5
Accretion of asset retirement
obligations
18.5
4.9
0.1
23.5
Exploration expenses
Dry holes and previously suspended
exploration costs
(0.7
)
—
34.8
34.1
Geological and geophysical
2.6
0.1
1.0
3.7
Other exploration
4.4
0.4
12.1
16.9
6.3
0.5
47.9
54.7
Undeveloped lease amortization
4.7
0.1
3.2
8.0
Total exploration expenses
11.0
0.6
51.1
62.7
Selling and general expenses
11.5
8.9
4.5
24.9
Other
138.1
2.8
0.4
141.3
Results of operations before taxes
923.5
94.5
(46.8
)
971.2
Income tax provisions (benefits)
179.1
24.6
0.9
204.6
Results of operations (excluding Corporate
segment)
$
744.4
69.9
(47.7
)
766.6
1 Includes results attributable to a
noncontrolling interest in MP GOM.
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Dollars per barrel
of oil equivalents sold)
2023
2022
2023
2022
United States – Eagle Ford Shale
Lease operating expense
$
11.48
11.41
$
13.06
11.81
Severance and ad valorem taxes
3.68
5.07
3.93
5.10
Depreciation, depletion and amortization
(DD&A) expense
26.48
25.57
26.35
25.67
United States – Gulf of Mexico1
Lease operating expense
$
14.72
10.25
$
14.71
10.63
Severance and ad valorem taxes
0.07
0.07
0.08
0.08
DD&A expense
11.44
9.86
11.33
9.71
Canada – Onshore
Lease operating expense
$
6.01
6.82
$
6.38
7.14
Severance and ad valorem taxes
0.07
0.06
0.07
0.07
DD&A expense
5.65
6.55
5.82
6.81
Canada – Offshore
Lease operating expense
$
10.96
11.60
$
12.60
13.63
DD&A expense
9.48
11.51
9.40
11.96
Total E&P continuing operations
Lease operating expense
$
11.21
9.41
$
11.76
9.80
Severance and ad valorem taxes
0.74
1.12
0.72
1.11
DD&A expense
12.44
12.51
12.27
12.41
Total oil and gas continuing operations –
excluding noncontrolling interest
Lease operating expense
$
11.02
9.36
$
11.58
9.70
Severance and ad valorem taxes
0.76
1.18
0.75
1.17
DD&A expense
12.53
12.64
12.36
12.56
1 Includes results attributable to a
noncontrolling interest in MP GOM.
MURPHY OIL CORPORATION
CAPITAL EXPENDITURES
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Millions of
dollars)
2023
2022
2023
2022
Exploration and production
United States1
$
245.5
225.4
$
500.2
418.2
Canada
75.4
74.0
143.5
150.9
Other
37.8
12.5
44.7
42.3
Total
358.7
311.9
688.4
611.4
Corporate
3.6
5.2
9.9
10.5
Total capital expenditures - continuing
operations2
362.3
317.1
698.3
621.9
Charged to exploration expenses3
United States1
81.9
2.2
83.6
6.3
Canada
0.1
0.4
0.2
0.5
Other
31.2
8.8
36.8
47.9
Total charged to exploration expenses -
continuing operations
113.2
11.4
120.6
54.7
Total capitalized
$
249.1
305.7
$
577.7
567.2
1 Includes results attributable to a
noncontrolling interest in MP GOM.
2 For the three months ended June 30,
2023, total capital expenditures excluding acquisition-related
costs (Côte d’Ivoire and Vietnam) of $32.3 million (2022: $46.5
million) and noncontrolling interest (NCI) of $29.9 million (2022:
$5.0 million) is $300.1 million (2022: $265.6 million). For the six
months ended June 30, 2023, total capital expenditures excluding
acquisition-related costs of $32.3 million (2022:$46.5 million) and
noncontrolling interest (NCI) of $38.8 million (2022: $8.6 million)
is $627.2 million (2022: $566.8 million).
3 For the three-month and six-month-ended
June 30, 2023, charges to exploration expense excludes amortization
of undeveloped leases of $2.7 million (2022: $3.7 million) and $5.4
million (2022 $8.0 million), respectively. For the three-month and
six-months ended June 30, 2023, charges to exploration expense
excluding previously suspended exploration costs of $17.1 million
(2022: $0) and NCI of $26.3 million (2022: $0) is $69.8 million
(2022: $11.4 million) and $77.2 million (2022: $54.7 million),
respectively.
MURPHY OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of
dollars)
June 30, 2023
December 31, 2022
ASSETS
Current assets
Cash and cash equivalents
$
369,355
491,963
Accounts receivable
409,989
391,152
Inventories
62,450
54,513
Prepaid expenses
27,354
34,697
Total current assets
869,148
972,325
Property, plant and equipment, at cost
8,426,045
8,228,016
Operating lease assets
867,353
946,406
Deferred income taxes
40,678
117,889
Deferred charges and other assets
46,306
44,316
Total assets
$
10,249,530
10,308,952
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt,
finance lease
$
705
687
Accounts payable
584,107
543,786
Income taxes payable
23,539
26,544
Other taxes payable
32,091
22,819
Operating lease liabilities
258,278
220,413
Other accrued liabilities
135,788
443,585
Total current liabilities
1,034,508
1,257,834
Long-term debt, including finance lease
obligation
1,823,521
1,822,452
Asset retirement obligations
843,328
817,268
Deferred credits and other liabilities
299,089
304,948
Non-current operating lease
liabilities
624,736
742,654
Deferred income taxes
235,665
214,903
Total liabilities
4,860,847
5,160,059
Equity
Common Stock, par $1.00
195,101
195,101
Capital in excess of par value
861,951
893,578
Retained earnings
6,259,561
6,055,498
Accumulated other comprehensive loss
(495,783
)
(534,686
)
Treasury stock
(1,586,522
)
(1,614,717
)
Murphy Shareholders' Equity
5,234,308
4,994,774
Noncontrolling interest
154,375
154,119
Total equity
5,388,683
5,148,893
Total liabilities and equity
$
10,249,530
10,308,952
MURPHY OIL CORPORATION
PRODUCTION SUMMARY
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
(Barrels per day unless otherwise
noted)
2023
2022
2023
2022
Net crude oil and condensate
United States
Onshore
26,880
26,304
23,100
23,334
Gulf of Mexico 1
72,022
63,427
73,850
59,363
Canada
Onshore
3,097
4,419
3,190
4,400
Offshore
2,913
3,128
2,687
3,224
Other
212
1,383
240
833
Total net crude oil and condensate -
continuing operations
105,124
98,661
103,067
91,154
Net natural gas liquids
United States
Onshore
4,328
5,178
4,243
5,006
Gulf of Mexico 1
6,291
4,913
6,316
4,223
Canada
Onshore
558
859
691
921
Total net natural gas liquids - continuing
operations
11,177
10,950
11,250
10,150
Net natural gas – thousands of cubic feet
per day
United States
Onshore
24,195
29,651
24,178
28,512
Gulf of Mexico 1
69,904
63,703
72,539
59,902
Canada
Onshore
352,265
288,019
328,878
273,237
Total net natural gas - continuing
operations
446,364
381,373
425,595
361,651
Total net hydrocarbons - continuing
operations including NCI 2,3
190,695
173,173
185,250
161,579
Noncontrolling interest
Net crude oil and condensate – barrels per
day
(5,949
)
(7,962
)
(6,279
)
(8,044
)
Net natural gas liquids – barrels per
day
(204
)
(319
)
(218
)
(303
)
Net natural gas – thousands of cubic feet
per day 2
(1,751
)
(3,097
)
(2,051
)
(2,845
)
Total noncontrolling interest
(6,445
)
(8,797
)
(6,839
)
(8,821
)
Total net hydrocarbons - continuing
operations excluding NCI 2,3
184,250
164,376
178,411
152,758
1 Includes net volumes attributable to a
noncontrolling interest in MP GOM.
2 Natural gas converted on an energy
equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP
GOM.
MURPHY OIL CORPORATION
WEIGHTED AVERAGE PRICE
SUMMARY
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
2023
2022
2023
2022
Crude oil and condensate – dollars per
barrel
United States
Onshore
$
72.39
110.66
$
73.47
$
103.39
Gulf of Mexico 1
73.82
109.55
73.54
102.76
Canada 2
Onshore
68.50
100.51
71.46
96.84
Offshore
80.14
115.65
79.26
113.46
Other
—
86.51
89.05
86.51
Natural gas liquids – dollars per
barrel
United States
Onshore
16.60
38.29
19.28
38.30
Gulf of Mexico 1
20.16
40.46
22.89
41.95
Canada 2
Onshore
29.90
63.99
39.82
59.23
Natural gas – dollars per thousand cubic
feet
United States
Onshore
1.88
7.06
2.19
5.89
Gulf of Mexico 1
2.33
7.52
2.81
6.43
Canada 2
Onshore
1.85
2.78
2.17
2.66
1 Prices include the effect of
noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
MURPHY OIL CORPORATION
FIXED PRICE FORWARD SALES AND
COMMODITY HEDGE POSITIONS (unaudited)
AS OF AUGUST 1, 2023
Volumes
(MMcf/d)
Price/MCF
Remaining Period
Area
Commodity
Type 1
Start Date
End Date
Canada
Natural Gas
Fixed price forward sales
250
C$2.35
7/1/2023
12/31/2023
Canada
Natural Gas
Fixed price forward sales
162
C$2.39
1/1/2024
12/31/2024
Canada
Natural Gas
Fixed price forward sales
25
US$1.98
7/1/2023
10/31/2024
Canada
Natural Gas
Fixed price forward sales
15
US$1.98
11/1/2024
12/31/2024
1 Fixed price forward sale contracts are
accounted for as normal sales and purchases for accounting
purposes.
MURPHY OIL CORPORATION
THIRD QUARTER 2023 GUIDANCE
Oil
BOPD
NGLs
BOPD
Gas
MCFD
Total
BOEPD
Production – net
U.S. – Eagle Ford Shale
27,000
4,900
27,900
36,600
– Gulf of Mexico excluding NCI
65,900
6,200
66,200
83,100
Canada – Tupper Montney
—
—
380,400
63,400
– Kaybob Duvernay and Placid Montney
2,900
700
12,700
5,700
– Offshore
2,900
—
—
2,900
Other
300
—
—
300
Total net production (BOEPD) - excluding
NCI 1
188,000 to 196,000
Exploration expense ($ millions)
$32
FULL YEAR 2023 GUIDANCE
Total net production (BOEPD) - excluding
NCI 2
180,000 to 186,000
Capital expenditures – excluding NCI ($
millions) 3
$950 to $1,025
¹ Excludes noncontrolling interest of MP
GOM of 5,700 BOPD of oil, 200 BOPD of NGLs, and 2,100 MCFD gas.
² Excludes noncontrolling interest of MP
GOM of 6,100 BOPD of oil, 200 BOPD of NGLs, and 2,100 MCFD gas.
³ Excludes noncontrolling interest of MP
GOM of $72 million and acquisition-related costs of $45
million.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20230801023508/en/
Investor Contacts:
InvestorRelations@murphyoilcorp.com Kelly Whitley, 281-675-9107
Megan Larson, 281-675-9470 Nathan Shanor, 713-941-9576
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