murphy oil corp. 2013 tudor pickering holt energy conference

M U R P H Y O I L C O R P O R AT I O N

Tudor Pickering Holt

2013 Energy Conference

Roger Jenkins

Executive Vice President & COO

June 20, 2013

M U R P H Y O I L C O R P O R A T I O N w w w . m u r p h y o i l c o r p . c o m N Y S E : M U R 2

Cautionary Statement

Cautionary Note to U.S. Investors - The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved and probable reserves. We use certain terms in this presentation, such as “reserve estimates”, “contingent resource”, “gross or total resource”, “resource base”, “possible reserves”, “EUR or estimated ultimate recovery” and similar terms that the SEC’s rules strictly prohibit us from including in filings with the SEC.

This presentation contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. 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, uncontrollable natural hazards and the failure to complete the spin-off of Murphy USA within the currently contemplated timeframe, because of adverse market conditions or tax consequences, among other things. For further discussion of risk factors, see Murphy’s 2012 Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.


On-Going US Retail Spin

Strategic Plan Focus

Resource and Capital Allocation

Proper Peer Group

Pure E&P U.S. Retail


Focus On Shareholders

Special Dividend of $2.50 per Share – Approximately $500 Million

Authorized Share Repurchase up to $1 Billion

First $250 Million; Retired 4,064,261 shares; Announced Dec 10, 2012

2nd Tranche of $250 Million; Announced May 23, 2013

Regular Dividend – Consistent Growth; Well Positioned in Peer Group

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 0%

1%

2%

3%

4%

5%

MU

R

Dividend Yield % Dividends, $/share

Peer Group: APA, APC, CHK, COP, DVN, ECA, EOG, HES, MRO, NBL, OXY, TLM


Top Tier Production Growth

Oil Weighted

Continued Growth to 2016 & Beyond

Onshore Growth and Well Count–Improving External Guidance

Sustainable Growth Record

0

50

100

150

200

250

300

2007 2008 2009 2010 2011 2012 2013E 2014E 2015E 2016E

Oil & SK Gas Dry & Assoc. Gas

78%

85%

Net, MBOEPD M

UR

-10%

-5%

0%

5%

10%

15%

20%

5-Year Production CAGR

Peer Group: APA, APC, CHK, COP, DVN, ECA, EOG, HES, MRO, NBL, OXY, TLM


Reserve Growth with Resource Migration Ahead

NA Dry

Gas 21%

EFS 19%

Syncrude

19%

Other

Projects 15%

Malaysia

Oil 16%

Malaysia Gas 8%

Kikeh Gas 2%

Reserves:

2012 Additions – 70 MMBOE

5 Year Average Replacement 160%

77% Oil & SK Gas Projects

Resources:

3.3 Billion BOE

70% Within Existing Development

2008 2009 2010 2011 2012

Proved Reserves MMBOE

402 439 455

534 604

Low Risk Migration

Current Capital Spend

Resource Plays

Syncrude

Proved Reserves Total Resources Proved

18%

Non - Proved

19%

Resource Play 22%

Conventional 11%

Heavy Oil 7%

Syncrude 8%

Deepwater 15%

Contingent 63%


Our Strategy

Develop Differentiated Perspectives In Underexplored Basins and Plays – The Key to Our Success

Continue to be a Preferred Partner to NOCs and Regional Independents

Complement our Offshore Business by Developing Unconventional Onshore Plays in North America

Develop and Produce Fields in a Safe, Responsible, Timely, and Cost Effective Manner

Achieve and Maintain a Sustainable, Profitable, Oil Weighted Portfolio

0

5

10

15

20

-10

0

10

20

MU

R M

UR

Adjusted to Exclude Discontinued Operations, After Tax Impairments, Corporate and Gains on Asset Sales. Peer Group: APA, APC, CHK, COP, DVN, ECA, EOG, HES, MRO, NBL, OXY, TLM

Upstream Income 2012 ($/boe) Upstream Income 1Q 13 ($/boe)


EXPLORATION


Exploration

Play Type Focus:

Large Structures in New Areas or Plays

Oil-Prone Deepwater Stratigraphic Plays

Multiple Structures -Cluster Development

Program Goal:

Consistent 10 Well per Year Program

Portfolio 2X Proved Reserves

1 Gulf of Mexico

4 Atlantic Margin

3 Southeast Asia

Focus Regions

2 Australia

1

2 3

4

Southeast Asia – Australia: Long Term LNG Projects with “Value Chain” Partners


Exploration Prospect Portfolio

*NA Onshore Excluded

0

100

200

300

400

500

600

700

0% 20% 40% 60% 80% 100%

Pg (Chance of Success) %

Gro

ss P

50

Re

sou

rces

(MM

BO

E)

2013 & Q1 2014 Wells

7,500 MMBOE Total P50 Gross

900 MMBOE P50 Net Risked

1.5x Proved Resources

75% Operated

-

20

40

60

80

100

120

140

160

2017 2018 2019 2020 2021 2022

Gross P50 Resource By Region

Risked Exploration, MBOEPD

Gulf of Mexico

Atlantic Margin

S.E. Asia

Australia

Serai & Bawang Putih

Dufresne Elombo DW

Titan

Ntem

Brunei

Australia 17%

Gulf of Mexico

23%

Atlantic Margin

34%

S.E. Asia 26%


Blacktail

Madagascar

2013 Exploration Program

BLOCK Q1 - ‘13 Q2 - ‘13 Q3 - ‘13 Q4 - ‘13 Q1 - ‘14

BRUNEI CA-2

INDONESIA Semai II

AUSTRALIA Browse Basin

CAMEROON Elombo & NTEM

USA Gulf of Mexico

Elombo - Deep Water

Kelidang NE-1

Elombo CB-1A

Bassett West-1

Dufresne-1

NTEM

Eupheme-1

Planned Well

Dry Hole/Non-Commercial

Oil Discovery

Gas Discovery

Titan

Keratau & Kempas

Serai-1 & Bawang Putih-1

Spud Range


Brunei LNG Lumut

BLOCK CA-2 (30% W.I.)

BLOCK CA-1 (5% W.I.) BLOCK K

Kikeh

Kakap- Gumusut

Siakap North- Petai

Kelidang NE

Brunei CA-2 Gas Exploration

BRUNEI Deep Offshore Block CA2

Kelidang NE-1 Discovery

2 Follow On Wells Late 2013

Murphy W.I. 30% Petronas, Shell, ConocoPhillips,

Mitsubishi - Partners

Existing LNG Plant

0 5km

Kelidang NE

Kelidang SW

Kempas

Keratau

Kelidang NE Follow Up Prospects


Australia Browse Basin

Murphy W.I. 20%

Large Prospects in a Proven Play

Bassett West-1

Found 20ft of Gas Pay

Potential Remains on Structure

Acquiring 3D Seismic

Dufresne-1

Spud Mid June

Results in Q3

Gross Resources 2 to 2.8 TCF


Cameroon – Impactful Prospects

Multiple Prospects and Leads

Stacked Fan Play Late Cretaceous

Early Tertiary

2,600 MMBOE Total Gross P50

Spud Elombo Well Early Q3

600 MMBOE 300 MMBOE

Drill Q1 ‘14 Drill Q3 ‘13


Gulf of Mexico

Long History of Success

3 Play Types

1,600 MMBOE Total Gross Resource P50

Multiple Prospects and Leads

Strong Position in Emerging Norphlet Oil Play

Titan

Murphy W.I. 70%

Jurassic Norphlet Play

Gross Resources 150 - 300 MMBOE

Spud Late 2013


GLOBAL OFFSHORE


Malaysia Shallow Water Developments

Patricia

1st Prod Oct ’13

Net Peak Rate: 1,100 BOPD ’14

Serendah

1st Prod Jun ’13


South Acis

1st Prod Sep ’13


Permas

1st Prod Dec ’13


0

5

10

15

20

25

30

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Future Fields Existing

Net, MBOPD Note: All Projects 85% W.I.


Malaysia: Block K

New 2013 Block K Production Kakap Floating Production

Unit

Siakap North/ Petai

Kikeh – Key Asset New Completion Designs

Working

Kakap Early Production System – To Plan

High Valued Crudes in SE Asia

0

20

40

60

80

100

120

140

Aug-10 Dec-10 Apr-11 Aug-11 Dec-11 Apr-12 Aug-12 Dec-12

Kakap Production

New Development (Gravel Pack)

Gravel Pack Repairs

Original Completion

-

5

10

15

20

25

2013 2014 2015 2016

Siakap North/ Petai

Kakap

Gro

ss, M

BO

PD

N

et,

MB

OEP

D


Sarawak Gas: Long Term Value

1.5 TCF P2 EUR Resources 1.1 TCF Total EUR Proven &

Certified

Phase II 640 BCF - Contracted

Oil-Indexed Gas Price

Production Ability to 2022 & Beyond

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

0

50

100

150

200

250

300

Sep-09 Mar-10 Sep-10 Mar-11 Sep-11 Mar-12 Sep-12 Mar-13 $

/MC

F

Gro

ss

, M

MC

FD

Rate Prices

0

100

200

300

400

500

600

2010 2011 2012

Gas Revenue - Opex, $MM

0

50

100

150

200

250

300

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Gro

ss, M

MC

FD

Phase I Phase II Make-Good Depletion

Phase I 250 MMCFD 5 Years from

2010

460 BCF

Phase II 250 MMCFD

7 Years

640 BCF

1.5 TCF P2 EUR


Malaysia Block H:

Next Gas Project

7 Consecutive Discoveries

1.5MTPA FLNG Operated by

PETRONAS

Progressing FLNG FEED

Phase 1 (950 BCF) Rotan, Alum, Bemban &

Buluh

10 Years Production

Targeting Sanction Late 2013

First Gas 2017

Block H Gross Estimated Resources of ~2300 BCF

Phase 2 Phase 3 Phase 4

0

100

200

300

1 6 11 16 21

Gas

Pro

du

ctio

n (

MM

CFD

)

Year

Phase 1 Phase 2 Phase 3 Phase 4

Murphy Net Entitlement = ~1,150 BCF


Building Back GOM Business

Strong Net Income & Cash Flow Provider

History of Ability

Favorable Terms & Regulator

-

10

20

30

40

50

2013 2014 2015 2016

# of Blocks???

Base Production

Dalmatian

Medusa Expansion

-

5

10

15

20

Q4 2012

2013 2014 2015 2016

Net, MBOEPD Opex per BOE

Dalmatian Project

Medusa Expansion


NORTH AMERICA ONSHORE


Seal – Long Term Focus

Recent Bolt-On

Land, Facility, Production

5,850 MMBBLS Oil In Place Significant Reserve Upside

Polymer Successful Pilot Project

Expected Recovery Increased 5-14%

Commercial Project Underway

Thermal Regulatory Approval Received

Started 1st CSS Pilot

7 Project Areas Identified

Successful Competitor Steam Pilot

Seal

Chipmunk

Gift

Dawson

0 6 Miles

Harmon Valley

Seal North

2013 Thermal Focus

2013 Polymer Focus

Net , MBOEPD

0

10

20

30

40

50

2013 2015 2017 2019 2021 2023 2025

Thermal

Polymer Primary


Onshore Canada – Long View Properties

Add a map

150,000 Net Acres

Recent Liquids Success

Montney:

Option on Gas Price 3.6 TCF Resource @ $4.50

5.4 TCF Resource @ $5.00

> 8 TCF Resource @ $6.00

Quality – De-risked Sub-Surface Asset

LNG Long Term Option

Syncrude:

Complements Global Offshore

Unique Low-risk, Steady Oil Production – Not Easy To Replicate

Huge Remaining Resource

Option Value Oil Prices $-

$50

$100

$150

$200

$250

$300

-

5

10

15

20

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Syncrude Production Profile, MBOPD Production EBITDAX $MM


0

5

10

15

20

25

30

35

40

Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13

Ground Floor Entry – High Value

300 MMBO Net

Largest in Company History

87 MMBOE Proved

De-risked by Industry

Drilling & Completions Improvement

Transportation & Quality Advantaged

High Margin Upside:

Down Spacing

Pearsall Shale

Eagle Ford Shale – New Legacy Asset

Net, MBOEPD

0 10 mi

TILDEN

N TILDEN

CATARINA

KARNES

Pearsall

Focus

Area

158,661 Net Acres

90% Oil + Condensate

9 Rigs

3 Frac Crews

0

20

40

60

80

2012 2013 2014 2015 2016

Net, MBOEPD

281 Wells Drilling

231 Producing Wells

16 Facilities

Pipeline Projects in Place

-

20

40

60

80

100

120

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Upside

Base

NUECES


EFS - Improving Cost Structure

-

5

10

15

20

25

30

35

40

2011 2012 2013 Q1

2013 2014 2015 2016

EFS Overall Opex, $/BOE

Drilling & Completion Improvements

Driving Capital Efficiency and Margin Improvement

$1,210

$763

$/Completed Lateral ft

35% $291

$169

$/ft

EFS Completion Cost EFS Drilling Cost

42%

0

10

20

30

40

50

60

70

80

90

100

2010 Q1 2011 Q1 2012 Q1 2013 Q1

Tilden Lifting Cost ($/BOE)

% Facilities Complete

Wells on Production


Financial Stability

Capex & Cash Flow, $MM Returning to Free Cash Flow

Recent Debt

Recapitalization

EFS Development

Liquidity Sources

Cash Flow

Revolver

US Retail Dividend

UK Downstream Sale

0%

10%

20%

30%

40%

50%

0.0

0.5

1.0

1.5

2.0

2.5

1970 1975 1980 1985 1990 1995 2000 2005 2010

LTD % Debt/Cap

Historically Low Debt $ Billion

0

1,000

2,000

3,000

4,000

5,000

6,000

2013 2014 2015 2016

Downstream Corporate

EFS Exploration (ex. EFS)

Development (ex. EFS) Cash flow

E&P Integrated

Refer to Appendix for Non-GAAP Financial Measures

$100 Brent, $85 WTI in 2014; $95 Brent, $90 WTI From 2015


Quality Assets with High Margins - EBITDAX/BOE

Refer to Appendix for Non-GAAP Financial Measures

$100 Brent, $85 WTI in 2014; $95 Brent, $90 WTI From 2015

EFS

GOM

Montney

Canada Offshore

Syncrude

Shallow

Water Malaysia

Deep Water Malaysia*

Seal

E&P 2012†

Total 2016*

(40)

(20)

-

20

40

60

80

- 20 40 60 80

2016 EBITDAX/BOE

Production Growth 2012 – 2016, MBOEPD

* Excludes Sabah Gas. † Excludes Sabah Gas, UK & Congo.

US ONSHORE $/BOE 2012 $60 Q1 2013 $66

CANADA ONSHORE $/BOE 2012 $21 Q1 2013 $18

MALAYSIA* $/BOE 2012 $66 Q1 2013 $67

CANADA OFFSHORE $/BOE 2012 $89 Q1 2013 $95

US OFFSHORE $/BOE 2012 $55 Q1 2013 $69


Takeaways

Growth is Visible, High-Margin & Oil-Weighted

Exploration First – Four High-Impact Tests in Next 12 Months

Complementary Onshore – Eagle Ford a New Legacy Asset

Rich Portfolio of Discovered Resources – Low-Risk Migration

Proven Onshore Capability – New Avenue to Capture Value


APPENDIX


Non-GAAP Financial Measure Definitions & Reconciliations

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


Non-GAAP Reconciliation

EBITDAX Murphy defines EBITDAX as income from continuing operations before income taxes, exploration expenses, depreciation, depletio n and amortization (DD&A), and net interest expense. Management believes that EBITDAX provides useful information for assessing Murphy's financial condition and results of operat ions 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. EBITDAX, 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). EBITDAX has certain limitations regarding financial assessments because it excludes certain it ems that affect net income and net cash provided by operating activities. EBITDAX should not be considered in isolation or as a substitute for a n analysis of Murphy's GAAP results as reported.

$ Millions

Year Ended December 31, 2012

Three Months March 31, 2013

Income from continuing operations before income taxes 1,623 403

Exploration Expense 381 108

DD&A 1,376 394

Interest expense, net of interest capitalized 15 14

Consolidated EBITDAX (Non-GAAP) 3,395 919


Non-GAAP Reconciliation

CASH FLOW Murphy defines Cash Flow as net cash provided by operating activities before changes in noncash operating working capital, ge ological and geophysical expenses and other exploration expenses, proceeds from sale of property of discontinued operations, expenditures for major repairs and abandonments, and other minor amounts, net. Management uses Cash Flow because it is useful in comparisons with capital expenditures as it excludes changes in working cap ital and all exploration expenses. Management uses Cash Flow to identify how much of the Company’s capital expenditure program is funded with internally generated cash flows.

$ Millions

Year Ended December 31, 2012

Three Months March 31, 2013

Net cash provided by operating activities 3,056 921

Change in noncash operating working capital 401 (211)

Geological & geophysical expense 32 39

Other exploration expenses* 37 13

Recovery of property net book value for discontinued operations -- 46

Expenditures for major repairs & abandonments 40 16

Other minor items, net (26) 20

Consolidated Cash Flow (Non-GAAP) 3,540 844

*Excludes expenses for dry holes and amortization of undeveloped leases.


Abbreviations

3D: three-dimensional

BBL: barrels (equal to 42 US gallons)

BCF: billions of cubic feet

BCFE: billions of cubic feet equivalent

BOE: barrels of oil equivalent (1 barrel of oil or 6000 cubic feet of natural gas)

BOPD: barrels of oil per day

CAGR: compound annual growth rate

Capex: capital expenditures

EBITDAX: income from continuing operations before taxes, exploration expenditures, depreciation, depletion and amortization, and net interest expense

EOR: enhanced oil recovery

EUR: expected ultimate recovery

FLNG: floating liquefied natural gas

FPSO: floating production, storage, and offloading vessel

GOM: Gulf of Mexico

MBO: thousands of barrels of oil

MBOEPD: thousands of barrels of oil equivalent per day

MBOPD: thousands of barrels of oil per day

MMBO: millions of barrels of oil

MMBOE: millions of barrels of oil equivalent

MMBTU: millions of British thermal units

MMCF: millions of cubic feet

NA: North America

NGL: natural gas liquid

NOC: national oil company

Opex: operating expenditures

PDP: proved developed producing

PUD: proved undeveloped

R/P: ratio of reserves to annual production

TCF: trillions of cubic feet

TPY: tons per year

TRIR: total recordable incident rate

VOC: volatile organic compound

WI: working interest

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

YTD: year-to-date