Murphy Oil Corporation Announces Preliminary Fourth Quarter and Full Year 2017 Financial and Operating Results, 2018 Capital Investment Program

Murphy Oil Corporation (NYSE: MUR) today announced its financial and
operating results for the fourth quarter ended December 31, 2017,
including a net loss from continuing operations of $285 million, or
$1.65 per diluted share. The fourth quarter loss included a $274 million
charge associated with U.S. tax reform.

The company’s income from continuing operations before income taxes, was
$2 million in the fourth quarter, and $72 million for the full year
2017. Financial highlights for the fourth quarter and full year 2017
include:

• Achieved competitive EBITDAX per barrel of oil equivalent over $22 in
  the fourth quarter
• Generated free cash flow from offshore assets near $120 million in the
  fourth quarter, and over $500 million for 2017
• Lowered lease operating expense for onshore assets achieving a company
  record low in Eagle Ford Shale of $6.70 per barrel and $4.50 per
  barrel in Canada
• Reduced selling and general expenses by 21 percent quarter-over-quarter
• Maintained approximately $1.0 billion of cash on balance sheet at
  year-end 2017, totaling five sequential quarters at this level

Operating highlights for the fourth quarter and full year 2017 include:

• Increased onshore production by 16 percent, quarter-over-quarter,
  excluding asset sales, driven by increased Kaybob Duvernay production
  of 31 percent, quarter-over-quarter
• Replaced 123 percent of total reserves with a one year finding and
  development cost of $13.09 per barrel of oil equivalent
• Solidified 2018 Gulf of Mexico near-infrastructure drilling schedule
  by farming into King Cake prospect and planning for Samurai
  delineation well

FOURTH QUARTER 2017 RESULTS

Murphy recorded a net loss from continuing operations of $285 million,
or $1.65 per diluted share, for the fourth quarter 2017. The company
reported adjusted income, which excludes both the results of
discontinued operations and certain other items that affect
comparability of results between periods, of $13 million, or $0.08 per
diluted share. The adjusted income excludes the following items
after-tax: the impact from the Tax Cuts and Jobs Act of $274 million, a
foreign exchange gain of $22 million, a loss of $20 million from
mark-to-market of open crude oil hedge contracts, a write down of
inventory materials value of $14 million, and a redetermination expense
of $9 million. The redetermination expense relates to a liability for
past revenues and costs from an overall change in the unitization of the
Kakap Gumusut field by the governments of Malaysia and Brunei. Details
for fourth quarter results can be found in the attached schedules.

Earnings before interest, taxes, depreciation and amortization (EBITDA)
from continuing operations totaled $289 million, or $19.10 per barrel of
oil equivalent (boe) sold. Earnings before interest, taxes,
depreciation, amortization and exploration expenses (EBITDAX) totaled
$334 million, or $22.12 per boe sold. Both EBITDA and EBITDAX for the
fourth quarter included certain one-off items that reduced those
balances by $21 million. Details for fourth quarter EBITDA and EBITDAX
reconciliation can be found in the attached schedules.

Production in the fourth quarter 2017 averaged 168 thousand barrels of
oil equivalent per day (Mboepd). Production was impacted in the quarter
due to the following temporary factors: delayed production recovery
following Hurricane Harvey along with shut-ins for offset operator fracs
in the Eagle Ford Shale of 900 barrels of oil equivalent per day
(boepd); unplanned downtime at the non-operated Habanero field, which is
shut-in due to a fire at the Enchilada facility, and unplanned downtime
at the non-operated Hibernia field for a combined total of 900 boepd;
and the impacts from Typhoon Tembin and Tropical Storm Kai Tak in
Malaysia of 800 boepd.

“Over the course of the year, we stabilized our production. We achieved
higher fourth quarter 2017 production year-over-year, which was
primarily driven by a 16 percent increase from our onshore business,
when adjusted for asset sales,” stated Roger W. Jenkins, President and
Chief Executive Officer. “Our constant focus on cost reductions,
consistent cash balance, premium price-advantaged portfolio, and the
ongoing financial strategy of spending within cash flow places our
company in an excellent position moving forward.”

FULL YEAR 2017 RESULTS

Murphy recorded a net loss from continuing operations of $311 million,
or $1.81 per diluted share, for the full year 2017. The company reported
an adjusted loss, which excludes both the results of discontinued
operations and certain other items that affect comparability of results
between periods, of $22 million, or $0.13 per diluted share. Details for
full year 2017 results can be found in the attached schedules.

EBITDA from continuing operations totaled $1,211 million, or $20.42 per
boe sold. EBITDAX totaled $1,334 million, or $22.49 per boe sold.
Production for full year 2017 averaged 164 Mboepd.

The company continued to emphasize cost control during 2017, achieving a
full year lease operating expense of $7.89 per boe, flat with 2016 in a
year of onshore service cost inflation. In addition, 2017 selling and
general expenses were $223 million, a 16 percent reduction from 2016.

FINANCIAL POSITION

As of December 31, 2017, the company had $2.8 billion of outstanding
fixed-rate notes and approximately $1.0 billion in cash and cash
equivalents. The fixed-rate notes have a weighted average maturity of
8.8 years and a weighted average coupon of 5.5 percent. The next senior
note maturity for the company is in 2022. There were no borrowings on
the $1.1 billion unsecured senior credit facility, which was extended to
2021, at quarter end.

IMPACT FROM THE TAX CUTS AND JOBS ACT

On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and
Jobs Act (“the Act”). For the year ended December 31, 2017, Murphy
recorded a provisional tax expense of $274 million. The charge includes
the impact of deemed repatriation of foreign income and the
re-measurement of deferred tax assets and liabilities. Murphy will
receive cash refunds of $30 million over the next four years relating to
Alternative Minimum Taxes (AMT) paid in an earlier year. Murphy
continues to assess the impact of this legislation including, among
other things, the carry-forward of 2017 net operating losses, the change
to U.S. federal tax rates, the possible limitations on the deductibility
of interest paid, the option for expensing of capital expenditures, the
migration from a “worldwide” system of taxation to a territorial system,
and the use of certain border adjustments. The provisional tax expense
recorded in 2017 is based on a reasonable estimate. The ultimate impact
of the Act may differ from these estimates due to changes in
interpretations and assumptions made by the company, as well as
additional regulatory guidance that may be issued.

Under the Act, the company will have the flexibility to repatriate most
past and future foreign earnings tax-free, except for a five percent
withholding tax required to be paid on Canadian earnings repatriated to
the U.S. parent company. The company’s statutory U.S. tax rate is 21
percent beginning in 2018, a decrease from the previous rate of 35
percent.

YEAR-END 2017 PROVED RESERVES

Murphy’s preliminary year-end 2017 proved reserves are 698 million
barrels of oil equivalent (Mmboe) an increase from 685 Mmboe at year-end
2016. The change in year-over-year reserves is mainly attributed to
additions from onshore assets, primarily oil-weighted Eagle Ford Shale
and Tupper Montney natural gas.

The company’s total reserves replacement was 123 percent with organic
reserves replacement of 113 percent. The reserve life index increased to
11.7 years from 10.6 years at year-end 2016. Final information related
to the company’s year-end 2017 proved reserves will be provided in
Murphy’s Form 10-K to be filed with the Securities and Exchange
Commission in February.

“We achieved another year of strong reserves replacement with total
proved reserves nearing 700 Mmboe, which puts us back to pre-asset sale
levels, and resulted in a competitive one year finding and development
cost of $13.09 per boe,” commented Jenkins.

REGIONAL OPERATIONS SUMMARY

North American Onshore

The North American onshore business produced over 96 Mboepd in the
fourth quarter, with 52 percent liquids. Fourth quarter 2017 operating
expenses were $5.68 per boe, a 21 percent decrease from fourth quarter
2016.

Eagle Ford Shale – Production in the quarter averaged 51 Mboepd,
with 90 percent liquids. During the quarter, the company brought 18
operated wells online, of which 15 were in the Catarina area, with an
average initial production rate over 30 days (IP30 rate) exceeding 1,090
boepd, and three were in the Karnes area. Of the three Karnes wells, two
were in the Austin Chalk and had an average IP30 rate over 1,070 boepd,
and one was in the Upper Eagle Ford Shale and had an IP30 rate over
1,400 boepd. The company continued implementing cost-saving solutions
resulting in a record company-low operating expense of $6.70 per boe, a
20 percent reduction from the same quarter in 2016.

In 2017, Murphy brought 78 Eagle Ford Shale wells online with 35 wells
in Karnes, 31 wells in Catarina, and 12 wells in Tilden. The company
continued proving the multi-stacked potential that is primarily in the
Karnes and Catarina areas with production from the Lower Eagle Ford
Shale, the Upper Eagle Ford Shale, and the Austin Chalk. The chart below
illustrates the areas, zones and IP30 rates for the 2017 online wells.

“We continue to see robust results across our Eagle Ford Shale business,
from reserves replacement to cost management to stacked pay potential.
The outcome of the 2017 program supports our estimate of nearly 800
remaining wells that are profitable below $40 per barrel West Texas
Intermediate (WTI) oil price. In addition, we have been able to
demonstrate a 150 percent improvement in Catarina IP30 rates over the
last five-year period,” commented Jenkins.

Midland Basin – In the fourth quarter, Murphy completed and
brought online two wells in Dawson County that are currently being
flowed back. At this time, oil rates are increasing as the wells
continue to clean up. Murphy has two contiguous land positions in Dawson
and Andrews Counties that total 30,800 net acres at an average cost of
$1,700 per acre. The acreage in Andrews County is prospective in the
Spraberry and Wolfcamp benches, as demonstrated by recent offset peer
company tests.

Tupper Montney – Natural gas production in the quarter averaged
223 million cubic feet per day (MMcfd). Murphy brought a five well pad
online in the Lower Montney with lateral lengths averaging greater than
10,000 feet. The Estimated Ultimate Recoveries (EURs) of these wells are
exceeding the 16 billion cubic feet (Bcf) type curve and trending in
line with 18 Bcf wells. Full cycle break-even costs continue to be less
than C$2.00 AECO per thousand cubic feet (Mcf). As a result of long-term
forward sales contracts and other marketing agreements, Murphy achieved
industry-leading fourth quarter netbacks in the Tupper Montney of C$2.49
per Mcf, and C$2.58 per Mcf for full year 2017. The company has
significantly reduced its future exposure to AECO prices through a
combination of forward sales contracts and market diversification to the
Malin, Chicago, Emerson and Dawn markets.

Kaybob Duvernay – Production in the quarter averaged over 4,100
boepd with 63 percent liquids, an increase of 31 percent from fourth
quarter 2016. During the fourth quarter, three wells were brought online
with peak rates greater than 1,000 boepd with 75 percent liquids. These
wells are performing at or above the pre-drill type curves, ranging from
650 to 800 Mboe. The company will continue to optimize completion
designs by testing well placement, lateral length, frac design and
flow-back strategy. During 2017, the company brought 11 Kaybob West
wells online, which are expected to have de-risked this area of the
play. Murphy has 200 locations at 1,000 foot well spacing de-risked in
the Kaybob West and Saxon areas. The company’s planned appraisal program
over the coming years is expected to yield an inventory of approximately
1,000 de-risked well locations across the play.

Global Offshore

The offshore business produced near 72 Mboepd for the fourth quarter,
with 72 percent liquids. Fourth quarter 2017 operating expenses were
$11.53 per boe.

Malaysia – Production in the quarter averaged over 48 Mboepd,
with 63 percent liquids. Block K and Sarawak averaged over 30 thousand
barrels of liquids per day, while Sarawak natural gas production
averaged over 99 MMcfd. The company’s ownership of the Kakap Gumusut
field, operated by Shell, was slightly lowered due to a recent
unitization agreement between the countries of Malaysia and Brunei that
has impacted various production sharing contracts across both borders.
The agreement altered the split between countries from 88/12 to 84/16 on
a Malaysia/Brunei basis. Effective January 1, 2018, Murphy’s working
interest was reduced by 0.195 percent resulting in the new overall
working interest in the Kakap Gumusut field of 6.78 percent. This
adjustment is reflected in Murphy’s production guidance and going
forward, the company will have oil production from Brunei.

North America – Production in the quarter for the Gulf of
Mexico and East Coast Canada averaged over 23 Mboepd, with 91 percent
liquids.

EXPLORATION UPDATE

Gulf of Mexico Exploration – During the fourth quarter, Murphy
farmed into the King Cake prospect (AT 23). Murphy has also planned and
is making final partner agreements for a Samurai (GC 432) delineation
well. Both prospects are in line with the company’s strategy of pursuing
oil-weighted, lower risk and lower working interest tie-back
opportunities, with estimated net well costs in the range of $18 to $22
million per well.

“We are pleased with our 2018 Gulf of Mexico exploration program as it
focuses on prospects close to existing infrastructure, with expected F&D
costs near $15 per barrel and break-even prices below $35 per barrel
WTI,” commented Jenkins. “With the tax reform in the U.S. and continued
low offshore service cost environment, we are expecting after-tax
internal rates of return for this program, on a full cycle basis, to now
exceed 30 percent on a modest $52 per barrel WTI price deck.”

Mexico Exploration – The company submitted the Exploration Plan
for Deepwater Block 5 to Mexico’s regulatory agency. Along with its
partners, Murphy expects to spud the first well late in the fourth
quarter of 2018 with an estimated net well cost of $15 million.

Vietnam Exploration – In the Cuu Long Basin Block
15-01/05, Murphy is progressing the field development plan, which is on
track for the Declaration of Commerciality in 2018.

Australia Exploration – Murphy added to its Vulcan Basin acreage
position by farming into the AC/P-21 block with a 40 percent
non-operated working interest. Currently, the company is acquiring 3D
seismic over this block with an optional well commitment in 2019. Should
a well be drilled, the net well cost is expected to be approximately $10
million.

2018 CAPITAL EXPENDITURE AND PRODUCTION GUIDANCE

Murphy is planning 2018 capital expenditures to be $1,056 million which
assumes an oil price of $50 to $55 per barrel WTI and a Henry Hub
natural gas price of $2.90 to $3.00 per Mcf. The table below illustrates
the capital allocation by area.

For 2018, Murphy has allocated $650 million of capital, or 62 percent,
to its North America onshore assets, which is a reduction of
approximately 18 percent from $791 million in 2017.

In the Eagle Ford Shale, Murphy will spend $330 million in 2018 which
includes 38 operated wells being brought online along with investments
for continued field development. The company has allocated $300 million
toward onshore Canadian assets in the Kaybob Duvernay, Placid Montney,
and Tupper Montney. In the Tupper Montney, production is expected to be
approximately 230 MMcfd per day, which is the volume required to keep
the third-party operated natural gas processing plant at full capacity.

Production for North America onshore assets, with conservative capital
spend in 2018, is expected to increase approximately nine percent, to
over 96,200 boepd as compared to 88,200 boepd in 2017, excluding asset
sales.

The Kaybob Duvernay and Placid Montney areas are expected to have annual
production over 11 Mboepd, a 92 percent increase from 2017. Production
in the Eagle Ford Shale is expected to be maintained close to full year
2017 levels, between 45,000 and 46,000 boepd.

Murphy has allocated $260 million of capital to its global offshore
assets. The capital is primarily related to three major offshore field
development projects: a subsea pump installation in the Gulf of Mexico,
a subsea gas lift project for the Kikeh field in Malaysia, and the
capital required in preparation to deliver gas into the PETRONAS
floating LNG project for Block H Malaysia. The subsea pump project in
the Gulf of Mexico will kick off production late in 2018 and it is
expected the Kikeh gas lift project will produce mid 2018. Each of these
projects are highly economic with planned internal rates of return
averaging nearly 50 percent based on a $52 per barrel WTI price. In
addition, investment is required for subsea equipment and drilling over
the next two years in conjunction with the PETRONAS floating LNG project
which remains on track to produce in 2020.

The company plans to allocate $106 million on exploration in 2018, with
45 percent for drilling, 20 percent for geological and geophysical
studies, and the remainder for other explorations costs.

Production for the first quarter 2018 is estimated to be in the range of
164 to 168 Mboepd with full year 2018 production to be in the range of
166 to 170 Mboepd. North America onshore unconventional production
represents 57 percent of full year guidance. Details on guidance can be
found in the attached schedules.

“Our 2018 capital program supports our strategy of investing in our
growing onshore assets while supporting our long-lived, free cash flow
providing offshore assets. Our increase in capital in 2018 is related to
investments in subsea projects along with our Block H FLNG project in
Malaysia. Our investment program is based on our strong desire to spend
within our means and provide free cash flow in addition to our current
dividend level. Our program is also strongly supported by our
diversified portfolio that provides high netback prices,” commented
Jenkins.

CONFERENCE CALL AND WEBCAST SCHEDULED FOR FEBRUARY 1, 2018

Murphy will host a conference call to discuss 2017 financial and
operating results as well as provide 2018 guidance and an updated
multi-year outlook on Thursday, February 1, 2018, at 11:00 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 1-833-832-5124, International
469-565-9821, reservation number 6498569. Replays of the call will be
available through the company’s website at http://ir.murphyoilcorp.com.

FINANCIAL DATA

Summary financial data, operating statistics and a summary balance sheet
for the fourth quarter 2017, 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 first quarter and full year 2018.

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 offshore production in Southeast Asia, Canada and Gulf of
Mexico, as well as North America onshore plays in the Eagle Ford Shale,
Kaybob Duvernay and Montney. Additional information can be found on the
company’s website at http://www.murphyoilcorp.com.

FORWARD-LOOKING STATEMENTS

This news release contains forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995.
Forward-looking statements are generally identified through the
inclusion of words such as “aim”, “anticipate”, “believe”, “drive”,
“estimate”, “expect”, “expressed confidence”, “forecast”, “future”,
“goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”,
“position”, “potential”, “project”, “seek”, “should”, “strategy”,
“target”, “will” or variations of such words and other similar
expressions. These statements, which express management’s current views
concerning future events or results, are subject to inherent risks and
uncertainties. Factors that could cause one or more of these future
events or results not to occur as implied by any forward-looking
statement include, but are not limited to, increased volatility or
deterioration in the level of crude oil and natural gas prices,
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.

RESERVE REPORTING TO THE SECURITIES EXCHANGE COMMISSION

The SEC requires oil and natural gas companies, in their filings with
the SEC, to disclose proved reserves that a company has demonstrated by
actual production or conclusive formation tests to be economically and
legally producible under existing economic and operating conditions. We
may use certain terms in this news release, such as “resource”, “gross
resource”, “recoverable resource”, “net risked P_MEAN
resource”, “recoverable oil”, “resource base”, “EUR” or “estimated
ultimate recovery” and similar terms that the SEC’s rules prohibit us
from including in filings with the SEC. The SEC permits the optional
disclosure of probable and possible reserves; however, we have not
disclosed the company’s probable and possible reserves in our filings
with the SEC. Investors are urged to consider closely the disclosures
and risk factors in our most recent Annual Report on Form 10-K filed
with the SEC and any subsequent Quarterly Report on Form 10-Q or Current
Report on Form 8-K that we file, available from the SEC’s website and
from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com.

Non-GAAP Financial Measures

Presented above is a reconciliation of Net loss to Adjusted
income/(loss). 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 loss as determined in
accordance with accounting principles generally accepted in the United
States of America.

Note: Amounts shown above as reconciling items between Net loss and
Adjusted income/(loss) are presented net of applicable income taxes
based on the estimated statutory rate in the applicable tax
jurisdiction. The 2017 pretax and income tax impacts for adjustments
shown above are as follows by area of operations.

Non-GAAP Financial Measures

Presented above is a reconciliation of Net loss to Earnings before
interest, taxes, depreciation and amortization (EBITDA) and Earnings
before interest, taxes, depreciation, amortization, and exploration
expenses (EBITDAX). Management believes EBITDA and 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. EBITDA and EBITDAX are
non-GAAP financial measures and should not be considered a substitute
for Net 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 equivalents sold and EBITDAX
per barrel of oil equivalents sold. Management believes EBITDA per
barrel of oil equivalents sold and EBITDAX per barrel of oil equivalents
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
EBITDAX per barrel of oil equivalent sold are non-GAAP financial metrics.

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