fourth quarter 2016 earnings conference call &...

Roger Jenkins

PRESIDENT & CHIEF EXECUTIVE OFFICER

FOURTH QUARTER 2016 EARNINGS

CONFERENCE CALL & WEBCAST

JANUARY 26, 2017

MURPHY OIL CORPORATION www.murphyoi lcorp.com NYSE: MUR 2

Cautionary Statement

Cautionary Note to U.S. Investors – The United States Securities and Exchange Commission permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. We may use certain terms in this presentation, such as “resource”, “gross resource”, “recoverable resource”, “net risked PMEAN resource”, “recoverable oil”, “resource base”, “EUR or estimated ultimate recovery” and similar terms that the SEC’s rules strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the oil and natural gas disclosures in Murphy’s 2015 Annual Report on Form 10-K on file with the SEC.

Forward-Looking Statements – This presentation contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Words such as “targets”, “expectations”, “plans”, “forecasts”, “projections”, and other comparable terminology often identify forward-looking statements. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could causeone or more of the events forecasted in this presentation not to occur include, but are not limited to, a deterioration in the business or prospects of Murphy, adverse developments in Murphy’s markets, or adverse developments in the U.S. or global capital markets, credit markets or economies generally. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, political and regulatory instability, and uncontrollable natural hazards. For furtherdiscussion of risk factors, see Murphy’s 2015 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.


4Q 16 Financial Overview

$MM (except per share)

4Q2016

4Q2015

FY2016

FY2015

Continuing Operations

Income (Loss) (62.8) (583.2) (273.9) (2,255.8)

$/Diluted Share (0.36) (3.39) (1.59) (12.94)

Adjusted Earnings

Adjusted Earnings (Loss) (26.9) (130.5) (230.1) (536.7)

$/Diluted Share (0.16) (0.76) (1.34) (3.08)

Adjusted Earnings 4Q 16 – Cont’d Ops• Mark-to-Market Loss on Crude Oil

• Redetermination Expense

• Foreign Exchange Gains

• Tax Benefits on Investments in Foreign Areas

Balance Sheet (Dec 31, 2016)• $3.0 BN Total Debt (Including Capital Lease)

• $1.0 BN Cash & Liquid Invested Securities

• 38% Total Debt / Total Capitalization

• 29% Net Debt / Total Capitalization

US WTI Hedges

2017: 22,000 bopd @ $50.41/bbl

AECO Hedges

2017: 124 MMcfd @ C$2.97/mcf2018 - 2020: 59 MMcfd @ C$2.81/mcf


Financial Position as of December 31, 2016

$0

$500

$1,000

$1,500

Senior Notes Undrawn RCF

10 YEAR 20 YEAR 30 YEAR

Debt Maturity Profile $ MM

• Total Liquidity $2.1 BN at YE 2016

• ~$1.0 BN of Cash and Liquid Invested Cash

• $1.1 BN Senior Unsecured Guaranteed Revolving Credit Facility Expire August 2019

• $630 MM of Unsecured Revolving Credit Facility Expire June 2017

• No Borrowings on Credit Facilities

• Cash On Hand to Meet Near Term Debt

• Net Increase in Cash and Cash Equivalents of $120 MM in 4Q 16

Maturity Profile

Total Bonds Outstanding $MM $2,800.0

Weighted Avg Fixed Coupon* 5.6%

Weighted Avg Years to Maturity* 10.1

*Long-term fixed rate notes


FY & 4Q 16 Overview

• 4Q 16 Production Averaged 168 Mboepd

• FY 16 Production Averaged 176 Mboepd, 168 Mboepd Excluding Divestitures

• Spent $605 MM* Capital Expenditures

• Balanced, Low Risk NA Onshore and Cash Generating Offshore Production

• Oil Weighted (~62% Liquids), Diversified Production Base

• ~$1.0 BN Cash & Liquid Invested Cash on Balance Sheet

• Reduced Costs Across the Company

• Reduced LOE per boe 15% Y-O-Y

• Reduced G&A Expense 14% Y-O-Y

• Adjusted Dividend While Maintaining Top Quartile Yield

• Increased Long-term Growth Opportunity Through Advantageous Portfolio Re-Balancing

• Expanded Exploration Portfolio Through GOM Farm-in & Deepwater Mexico Block

• Acquired Kaybob Duvernay/Placid Montney for C$265 MM – Bottom of Cycle

• Monetized Midstream Assets for C$539 MM – Top of Cycle

• Monetized Syncrude Interest for C$937 MM – Mid Cycle

• Monetized Seal Asset for C$65 MM – Mid Cycle

Progressing the Portfolio While

Maintaining Asset Balance

Maintaining Balance Sheet Strength

Through Capital Discipline

Stabilizing Production with

Lower 2016 Capital Spending

$

*Excludes $207 MM acquisition costs of Kaybob Duvernay/Placid Montney


67%

33%

35%

32%

3%

7%

23% Eagle Ford Shale

Canada Onshore

Canada Offshore

GOM

Malaysia

2016 E Proved Reserves685 MMboe

2016 Reserves

Onshore

Offshore

50% PDP50% PUD

58% Liquids & Oil-Indexed Gas

2016 Estimated Reserves

4

5

6

7

8

9

10

11

12

0

100

200

300

400

500

600

700

800

2012 2013 2014** 2015** 2016 E***

YearsMMboe Proved Reserves & Reserves Life

Proved R/P**2014 and 2015 includes impact of Malaysia Sell-Down***2016 includes impact of Syncrude Divestiture

• Divested High Costs, Heavy Oil Assets While Increasing NA Onshore Unconventional Portfolio

• Reserve Life Index 10.7 Years

• 3 Year 16% Increase in Reserves Life

• Organic Reserves Replacement 69%

• 3 Year Rolling Average of Reserve Replacement 154%

• 3 Year Cumulative F&D Costs of $15.98/boe

• SEC Benchmark Pricing• 2016 WTI $42.75, 15% Below 2015• 2016 AECO $1.65, 21% Below 2015

*Includes Syncrude divestiture of 113 MMboe

774

685

49

52

121

64 5

500

550

600

650

700

750

800

YE 2015 Divestitures* 2016 Production Price Impacts Technical Acquisitions YE 2016 E

-

-

-

MMboe

7MURPHY OIL CORPORATION www.murphyoi lcorp.com NYSE: MUR

PORTFOLIO REVIEW


Offshore 4Q 16 Highlights

MalaysiaSarawak• S. Acis Development

• 1st Gas Achieved• Recovered from FSO

Shutdown

Sabah• Kikeh & Siakap North Petai

• Planned Shutdown Completed Successfully and On Schedule

Gulf of MexicoDalmatian – 70% W.I. (Op.)• Subsea Pump Project Underway

Kodiak – 29% W.I. (Non-Op.)• Commingling Complete• 20,000 boepd Gross Production

Hoffe Park – 25% W.I. (Non-Op.)• Well Encountered Hydrocarbons

and Has Been Suspended While Delineation Plan Being Developed

Focused Offshore Opportunities• Gulf of Mexico

• Mexico – 30% W.I. (Op.) Successful in Bid Round at Block 5

• Vulcan & Ceduna Basins in Australia

• Malaysia & Vietnam


0

20,000

40,000

60,000

80,000

0 10 20 30 40 50 60 70

Cu

m G

ross

BO

E

Days on Production

Catarina – Briggs Ranch 3 Well Pad

Type Curve Briggs 3 Well Avg

Average Well 100% Above 315 MBOE Type Curve

• Catarina • 7,500 ft Completed Lateral Length in Lower EFS at Avg

D&C Cost $3.9 MM• Reduced Cluster Spacing, Longer Laterals, Higher Sand

Concentration, Allowing for Choke Increases• Improved Returns Rival Karnes Area

• Tilden• Seven 4Q 16 Wells Inline with Type Curve, 500 to 800 BOPD IP30s• Increased Sand Concentration & Reduced Cluster Spacing• Reduced Offset Frac Impact

• Eagle Ford Shale Opex reduced by 11% Y-O-Y

• Over 1,000 Premium Locations with Break-Even Price Below $38/bbl

Eagle Ford Shale 4Q & FY 2016 Highlights Eagle Ford Shale 4Q 16 FY 16

Total Production (boepd) 45,531 48,751

New Wells Online 17 53

Total Percent Liquids 88%

0

20,000

40,000

60,000

80,000

0 10 20 30 40 50 60 70 80 90

Cu

m G

ross

BO

E

Days on Production

Catarina – Stumberg 3 Well Pad

Type Curve Stumberg 3 Well Avg

Average Well 70% Above 538 MBOE Type Curve


Tupper Montney

• Completed 2 Wells During the Quarter• >9,300’ Laterals (1,000 lb/ft)• 19 BCF EUR Expected

• Currently Drilling 5 Well Pad to be Completed 1Q 17• Drilled Longest Lateral to Date >9,800 ft

• Full Cycle Break-Even C$2.05 AECO

Tupper Montney 4Q & FY 2016 Highlights Tupper Montney 4Q 16 FY 16

Total Production (MMcfd) 204 200

New Wells Online 2 8

-

200

400

600

800

1,000

1,200

- 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160C

um

ula

tive

Gas

Pro

du

ced

, mm

scf

Days on Production

10 BCF Type Curve

14 BCF Type Curve

17 BCF Type Curve

Recent Tupper West Well Performance


Kaybob Duvernay 4Q & FY 16 Highlights

Light Oil67K Acres

Lean Gas22K Acres

Black Oil110K Acres

Condensate33K Acres

4-36 PAD (4 Wells)Online 3Q 16

Kaybob Duvernay RightsJV AreaLight OilCondensateLean GasBlack Oil

1-18 PAD (2 Wells)Rigging Up to Frac

4-32 PAD (2 Wells)1Q 17 Drilling

0

200

400

600

800

0 20 40 60 80 100 120 140

4-36 B&C

4100' Type Curve 4-36B boepd 4-36C boepd

EUR 470 MBOE

0

100

200

300

400

500

600

700

800

900

0

1

2

3

4

5

6

7

8

9

10

CVX2014

ECA2014

CVX2015

ECA2015

Shell2015

CVX2016

ECA2016

MUR2016

MUR8000'

Shell2016

Drilling Cost (m USD) Lateral Length (ft) Cost per ft (USD)

2014

Peer A Peer B

2015

Peer A Peer B Peer C Peer C

2016

Peer A Peer B MUR

Competitive Drilling Costs

• 4 Well Pad (4-36)

• 4,100 ft Wells Performing to Plan at 470 MBOE Type Curve

• First Murphy 2 Well Pad (1-18) Spud 4Q 16

• Anticipated EUR >500 Gross Mboe (59% Liquids)• Lateral Length – 4,500 ft• Drilling Costs Avg $2.5 MM per Well• First Well Executed at Industry Benchmark

• Cost & Completion Improvements Ahead

11-18 PAD (3 Wells)1Q 17 Drilling

Co

st p

er f

t(U

SD)

–La

tera

l Len

gth

(*1

0 f

t)

Tota

l Wel

l Co

st, $

MM

*Source: IHS Rushmore Reviews 2012-2016 Q3

Kaybob Duvernay 4Q 16 FY 16

Total Production (boepd) 3,180 3,120

Total Percent Liquids 54% 51%

8,000’

bo

epd


LOOKING AHEAD


Financial Strategies

• Targeting Cash Flow Neutrality

• Preserving Financial Strength & Liquidity While Maintaining Dividend

• Continuing to Focus on Cost Structure Improvements

• Stabilizing Production to Prepare for Future Growth

Operating Strategies

• Appraising the Oil Window in the Duvernay Shale

• Driving Efficiencies While Delineating Multi-Zones in the Eagle Ford Shale

• Participating in High Return Offshore Projects

• Returning to Exploration at Bottom of Cost Cycle

2017 Capital Budget Strategy


41%

4%5%16%

4%2%

12%

3%

13%

Eagle Ford Shale

Tupper Montney

Placid Montney

Kaybob Duvernay

Canada Offshore

GOM

Malaysia

Other

Exploration

2017 Total Capex, $890 Million*

NA Onshore66%

Offshore34%

Field Development & Development Drilling ~85%

boepd

164

167

155,000

160,000

165,000

170,000

175,000

180,000

4Q 16 FY 16 1Q 17 E FY 17 EContinuing Ops Divested

166 - 170162 - 168168

176

*Inclusive of Kaybob Duvernay carry

Net Production

2017 Annual Capex Guidance at $890 MM • $590 MM Allocated to NA Onshore Unconventional

• Guidance Assumes $52/bbl WTI and $3.10/mcf HH

• Onshore Production Growth ~9%**

• Exploration $113 MM

2017 Production Guidance• 1Q 17 Guidance 166 – 170 Mboepd

• FY 17 Guidance 162 – 168 Mboepd• 62% Liquids

**Adjusted for asset sales

2017 Production & Capex Guidance


-

25

50

75

100

125

150

175

200

225

250

2017 2020

Net Production2017 – 2020 Plan

• Long Term Oil-Weighted Production Growth Within Cash Flow from Existing Assets

• Generating Cumulative Adjusted Free Cash Flow of ~$400 MM by 2020 with Dividend

• EBITDA CAGR ~15 – 20%

• Stable Offshore Production Providing Cumulative Free Cash Flow of ~$1.7 BN*

• Onshore Assets Drive Long Term Production Growth with Production CAGR of ~10 – 15%

Note: WTI Price $52/bbl 2017; 2018 $60/bbl assumes 2% inflation thereafterHH Price $3.10/mcf 2017; 2018 $2.91/mcf assumes 2% inflation thereafter*Not including corporate effects

Offshore Offshore

Onshore Onshore

Advantages of a Balanced Portfolio Driving Long Term Plan

mboepd


Growing Onshore Production by 9% Y-O-Y

Preserving Balance Sheet & Strong Liquidity

Leading EBITDA per boe Producer

Adding Reserves from M&A Leading to Below $10 F&D

Expanding Exploration Portfolio at Bottom of Cycle

Achieving Value-Added Top Tier D&C Performance

Establishing Foundation for Future Growth Within Cash Flow

Takeaways


APPENDIX


Appendix

• Non-GAAP Reconciliation

• Abbreviations

• Guidance

• Hedging Positions


Non-GAAP Financial Measure Definitions & Reconciliations

The following list of Non-GAAP financial measure definitions and related reconciliations is intended tosatisfy the requirements of Regulation G of the Securities Exchange Act of 1934, as amended. Thisinformation is historical in nature. Murphy undertakes no obligation to publicly update or revise anyNon-GAAP financial measure definitions and related reconciliations.


Non-GAAP Reconciliation

ADJUSTED EARNINGSMurphy defines Adjusted Earnings as net income adjusted to exclude discontinued operations and certain other items that affect comparability between periods.

Adjusted Earnings is used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

Adjusted Earnings, as reported by Murphy, may not be comparable to similarly titled measures used by other companies and it should be considered in conjunction with net income, cash flow from operations and other performance measures prepared in accordancewith generally accepted accounting principles (GAAP). Adjusted Earnings has certain limitations regarding financial assessmentsbecause it excludes certain items that affect net income. Adjusted Earnings should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.



ADJUSTED EARNINGS SCHEDULE$ Millions

Twelve Months Ended – December 31, 2016

Twelve Months Ended – December 31, 2015

Net Income (loss) (276.0) (2,270.8)

Discontinued operations loss 2.0 15.0

Mark-to-market loss (gain) on crude oil derivate contracts 81.2 (37.7)

Foreign exchange gains (52.3) (86.7)

Impairment of assets 68.9 1,660.0

Redetermination expense 24.2 -

Tax benefits on investments in foreign areas (21.7) (16.9)

Environmental provisions 4.5 35.8

Deepwater rig contract exit costs (benefits) (2.8) 183.3

Oil Insurance Limited dividends (4.5) (4.5)

Materials inventory loss 9.0 -

Syncrude operations, including tax benefits of $68.0 on sale (47.9) -

Income tax benefits associated with Montney midstream (20.9) -

Restructuring charges 6.2 14.1

Deferred tax on distributed foreign earnings - 188.5

Gain on sale of 10% interest in Malaysia - (218.8)

Increase in Alberta corporate tax rate - 23.8

Decrease in Malaysia corporate tax rate on certain fields - (21.8)

Adjusted Earnings (Loss) (230.1) (536.7)



EBITDAMurphy defines EBITDA as income from continuing operations before income taxes, depreciation, depletion and amortization (DD&A), net interest expense, and impairment expense.

Management believes that EBITDA provides useful information for assessing Murphy's financial condition and results of operations and it is a widely accepted financial indicator of the ability of a company to incur and service debt, fund capital expenditure programs, and pay dividends and make other distributions to stockholders. EBITDA per barrel is computed by taking EBITDA divided by total barrels of oil equivalents produced during the respective periods.

EBITDA, as reported by Murphy, may not be comparable to similarly titled measures used by other companies and it should be considered in conjunction with net income, cash flow from operations and other performance measures prepared in accordance with generally accepted accounting principles (GAAP). EBITDA has certain limitations regarding financial assessments because it excludes certain items that affect net income and net cash provided by operating activities. EBITDA should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.

$ MillionsTwelve Months Ended – December 31, 2016 Twelve Months Ended – December 31, 2015

Income (loss) from continuing operations (274.0) (2,255.8)

Income tax benefit (219.2) (1,026.5)

Interest expense, net of interest capitalized

148.2 117.4

DD&A expense 1,054.1 1,619.8


Consolidated EBITDA (Non-GAAP) 804.2* 948.1**

*Includes pre-tax charge for redetermination expense of $39.1 million**Includes pre-tax gain on sale of 10% interest in Malaysia of $155.1 million and pre-tax charge for deepwater rig contract exit costs of $282.0 million



EBITDAXMurphy defines EBITDAX as income from continuing operations before income taxes, exploration expenses, depreciation, depletion and amortization(DD&A), net interest expense, and impairment expense.

Management believes that EBITDAX provides useful information for assessing Murphy's financial condition and results of operations and it is a widelyaccepted financial indicator of the ability of a company to incur and service debt, fund capital expenditure programs, and pay dividends and make otherdistributions to stockholders. EBITDAX per barrel is computed by taking EBITDAX divided by total barrels of oil equivalents produced during the respectiveperiods.

EBITDAX, as reported by Murphy, may not be comparable to similarly titled measures used by other companies and it should be considered in conjunctionwith net income, cash flow from operations and other performance measures prepared in accordance with generally accepted accounting principles(GAAP). EBITDAX has certain limitations regarding financial assessments because it excludes certain items that affect net income and net cash providedby operating activities. EBITDAX should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.

$ MillionsTwelve Months Ended – December 31, 2016 Twelve Months Ended – December 31, 2015

Income (loss) from continuing operations (274.0) (2,255.8)

Income tax benefit (219.2) (1,026.5)

Interest expense, net of interest capitalized 148.2 117.4

DD&A expense 1,054.1 1,619.8


Exploration expense 101.9 470.9

Consolidated EBITDAX (Non-GAAP) 906.1* 1,419.0***Includes pre-tax charge for redetermination expense of $39.1 million**Includes pre-tax gain on sale of 10% interest in Malaysia of $155.1 million and pre-tax charge for deepwater rig contract exit costs of $282.0 million


Abbreviations

BBL: barrels (equal to 42 US gallons)

BCF: billions of cubic feet

BCFE: billion cubic feet equivalent

BN: billions

BOE: barrels of oil equivalent (1 barrel of oil or

6000 cubic feet of natural gas)

BOEPD: barrels of oil equivalent per day

BOPD: barrels of oil per day

CAGR: compound annual growth rate

D&C: drilling & completion

DD&A: depreciation, depletion & amortization

EBITDA: income from continuing operations

before taxes, depreciation, depletion and

amortization, and net interest expense

EBITDAX: income from continuing operations

before taxes, depreciation, depletion and

amortization, net interest expense, and

exploration expenses

MMBOE: millions of barrels of oil equivalent

MMCF: millions of cubic feet

MMCFD: millions of cubic feet per day

MMCFEPD: million cubic feet equivalent per day

MMSTB: million stock barrels

NA: North America

NGL: natural gas liquid

ROR: rate of return

R/P: ratio of reserves to annual production

TCF: trillion cubic feet

TCPL: TransCanada Pipeline

TOC: total organic content

WI: working interest

WTI: West Texas Intermediate (a grade of crude oil)

EFS: Eagle Ford Shale

EUR: estimated ultimate recovery

F&D: finding & development

FLNG: floating liquefied natural gas

G&A: general and administrative expenses

GOM: Gulf of Mexico

HCPV: hydrocarbon pore volume

JV: joint venture

LOE: lease operating expense

LLS: Light Louisiana Sweet (a grade of crude oil)

LNG: liquefied natural gas

MBOE: thousands barrels of oil equivalent

MBOEPD: thousands of barrels of oil equivalent

per day

MCF: thousands of cubic feet

MCFD: thousands cubic feet per day

MM: millions


Guidance – 1Q 2017

Guidance 1Q 20161Q 2017

Liquids (bopd)1Q 2017

Gas (mcfd)

Q Production: 103,500 387,000

US - Eagle Ford Shale 41,500 31,000

Gulf of Mexico 13,000 15,500

Canada – Tupper Montney - 211,500

Kaybob Duvernay & Placid Montney 2,000 11,000

Offshore 11,000 -

Malaysia – Sarawak 13,500 111,000

Block K 22,000 7,000

1Q Production Volume (boepd) 166,000 – 170,000

1Q Sales Volume (boepd) 158,000 – 162,000

1Q Exploration Expense ($MM) $25

Full Year 2017 Production (boepd) 162,000 – 168,000

Full Year 2017 Capex ($MM) $890

1Q Expected Realized Prices ($/bbl) Malaysia – Block K $52.26

Sarawak Oil $54.23

($/mcf) Sarawak Gas $3.50


2017 Hedging Positions

Field Commodity TypeVolumes (bbl/d) Price (USD/bbl) Start Date End Date

United Stated WTI Fixed Price Derivative Swap 22,000 $50.41 1/1/2017 12/31/2017

Field Commodity TypeVolumes

(MMcf/d) Price (CAD/mcf) Start Date End Date

Montney Natural Gas Fixed Price Forward Sales 124 C$2.97 1/1/2017 12/31/2017

Montney Natural Gas Fixed Price Forward Sales 59 C$2.81 1/1/2018 12/31/2020

fourth quarter 2016 earnings conference call &...

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