Murphy Oil : Goldman Sachs Global Energy Conference Investor Presentation Material

GOLDMAN SACHS GLOBAL ENERGY CONFERENCE

JANUARY 2020

ROGER W. JENKINS

PRESIDENT& CHIEF EXECUTIVE OFFICER

Cautionary Statement & Investor Relations Contacts

Cautionary Note to U.S. Investors - The United States Securities and Exchange Commission (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 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 prohibit us from including in filings with the SEC. The SEC permits the optional disclosure of 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.

Forward-Looking Statements - This presentation 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 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 presentation refers to certain forward looking non-GAAP measures such as future "Free Cash Flow" and future "EBITDA". Definitions of these measures are included in the appendix.

Kelly Whitley

VP, Investor Relations & Communications [e-mail]

Bryan Arciero

Sr. Investor Relations Advisor [e-mail]

Megan Larson

Sr. Investor Relations Analyst [e-mail]

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Agenda

01 COMPANY UPDATE

02 ONSHORE PORTFOLIO UPDATE

03 OFFSHORE PORTFOLIO UPDATE

04 EXPLORATION UPDATE

05 LOOKING AHEAD

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Murphy Overview

A History of Excellence

• Long corporate history, IPO 1956
• Global offshore and North American onshore portfolio
• Oil-weightedassets drive high margins
• Exploration renaissance in focus areas
• Consistent cash flows from long-term offshore assets
• Growing unconventional assets in North American onshore
• Low leverage with appropriate liquidity and strong balance sheet
• History of shareholder-focused dividend policy

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Murphy at a Glance

Post-Transaction Reserves*

	By Area		By Product Mix
27%
	37%	38%	62%
	760
			Liquids-	54%
	MMBOE
			Weighted
	36%		8%
US Onshore	Canada Onshore	NA Offshore	Crude oil	NGLs	Natural gas
	3Q 2019 Production
	By Area		By Product Mix
	26%
			34%	66%
44%	192
		Liquids-
	MBOEPD
			Weighted	59%
	29%		7%
US Onshore	Canada Onshore	NA Offshore	Crude oil	NGLs	Natural gas	Office	Exploration	Production

* Based on internal estimates as of January 1, 2019 using year-end SEC pricing. Includes MP GOM (excluding non-controlling interest) and LLOG asset acquisitions and Malaysia divestiture, and excludes Brunei (asset held for sale).

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Value-Adding Transformation

2016	2018	2019
Acquired Kaybob	Transaction	Acquired LLOG
Duvernay &	with Petrobras	Gulf of Mexico Assets
Placid Montney	Gulf of Mexico	$1.375 BN
$206 MM	$795 MM

2014 - 2015	2016 - 2017	2018 - 2019
Stabilizing & Rebuilding;	Reshaping Portfolio;
Repositioning Portfolio Post-Spin;
Strengthening Balance Sheet	Growing Oil-Weighted Assets
Streamlining Assets
Without Issuing Equity	with Free Cash Flow Generation

2014	2016	2016	2017	2019
Sell-Down	Divested	Divested	Divested	Divested
30% Malaysia	Montney	Syncrude	Heavy Oil	Malaysia
$2.0 BN	Midstream	$730 MM	$51 MM	$2.127 BN
	$412 MM

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Achieving Premium Oil-Weighted Realizations

>112,000BBLS/Day94%SOLD

SOLD 3Q 2019At Premium

to $56.45 WTI

Sales Volumes & Differentials

Eagle Ford	North America	3Q 2019 Total Company

	Shale	Offshore	Other
			Brent	32%	Mars
	>$2/BBL	>$4/BBL	6%	+$4.01/BBL
Premium to WTI	+$5.55/BBL
	4%
3Q 2019
	Differentials
				vs
			HLS	$56.45 WTI
EBITDA/BOE	$35/BOE	$37/BOE	+$5.50/BBL	22%	MEH
		+$4.57/BBL
3Q 2019		36%
FIELD-LEVEL

NOTE: Premium to WTI excludes transportation costs

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Eagle Ford Shale and Gulf of Mexico Deliver Strong Operating Cash Flows

Achieving High Operating Margins

• Generating >$50/BBL margins
• Allocating >75% of capital to Eagle Ford Shale and Gulf of Mexico
• Operating efficiencies result in low OPEX
• Timely hedging mitigates cash flow risk

3Q 2019 Operating Margins $/BBL

Eagle Ford Shale

Gulf of Mexico

$70

$62

$60$59

$50

$40

$52

$52

$30

$20

$10								$10
$7
$0
		Operating margin		Opex		Avg realized price

NOTE: Operating margin calculated as price realizations less operating expenses WTI $56.45/BBL in 3Q 2019.

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Long History of Benefitting Shareholders

Free Cash Flow $MM 2019E

• $6.3 Billion

Returned to Shareholders

Since 1961

• $4.4 Billion

Returned to Shareholders

In last 10 years

$500

$0

-$500

-$1,000

Note: FCF = 2019E Median Consensus Cash Flow from Operations less Annual CAPEX (12/31/2019)

Source: FactSet

Peer Group: APA, CHK, CNX, COG, DVN, ECA, HES, MRO, MTDR, NBL, RRC, SM, SWN, WLL, XEC

Dividend Yield

4%

2%

0%

Source: FactSet at 1/6/2020

Peer Group: APA, CHK, CNX, COG, DVN, ECA, HES, MRO, MTDR, NBL, RRC, SM, SWN, WLL, XEC

Note: No dividend paid by CHK, CNX, MTDR, SWN, WLL

• $1.6 Billion

in Share Repurchases

2012 - 1H 2019

Cash Paid to Shareholders $MM 1997 - 2019
$1,000
$800
$600
$400
$200
$0
97	98	99	00	01	02	03	04	05	06	07	08	09	10	11	12	13	14	15	16	17	18	19
					Dividends		Special Dividends	Repurchases

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Executing Our 2019 Plan

PRODUCING

GENERATING

INCREASING

TRANSFORMING

BUILDING

Oil-Weighted

High Margin

Capital Returns

Portfolio for

Profitable

Assets

Realizations

to Shareholders

Future Value

Production

Produced 192 MBOEPD,

94% oil volumes sold at

Completed $500 MM

Successfully bid on 3

Brought GOM Dalmatian

~60% Oil

premium to WTI

share buyback program

blocks in Brazil's Sergipe-

well online at >5,000

Alagoas Basin

BOEPD gross

Produced highest oil

Adjusted EBITDA $438 MM

Delivered 5%

volumes since 1Q 20151

highest since 4Q 2014

dividend yield

Farmed in to 3 blocks in

Completed multiple GOM

Brazil's Potiguar Basin

workover and tie-back

Increased Eagle Ford Shale

>$24 adj. EBITDA/BOE

Returned >$620 MM to

projects, first oil 4Q 2019

oil production >22% from

shareholders YTD 2019

Positioned to produce over

2Q 2019

>$36 EBITDA/BOE

200 MBOEPD in 4Q 2019

US & Canada offshore2

Benefitted shareholders

Lowered LOE/BOE by

within cash flow

13% from 2Q 2019 to <$8

Added oil hedges with 2020

including sale proceeds

average price >$53 WTI

1 Excluding Syncrude and heavy oil

2 Field level

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Onshore Portfolio Update

Concentrated Onshore Assets with Repeatable Results

Oil-Weighted Platform

Across North America

Kaybob Duvernay

11 MBOEPD at 3Q 2019, 58% oil, 69% liquids ~80 total producing wells online

Eagle Ford Shale

51 MBOEPD at 3Q 2019, 80% oil, 91% liquids ~1,005 total producing wells online

Well-Positioned for Natural Gas

Tupper Montney

269 MMCFD at 3Q 2019

~250 total producing wells online

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Significant Running Room in the Eagle Ford Shale

Significant Development Across ~125,000 Net Acres Eagle Ford Shale Acreage

• 500+ MMBOE total resource potential
• Conservative inter-well spacing, type curves account for parent/child relationship
• Completion designs optimized by pad & well
• Long life asset at low end of cost curve
• Remote operating center with big data focus

Long-Term Plan Well Cadence*

	200	5
	150	4	Number
Online
	3
Wells	100		Rigsof
	2
	50	1
	0	0

2019E	2020E	2021E	2022E	2023E
		Wells Online		Rigs Per Year

* As of December 31, 2018

KARNES

Atascosa

Karnes

La Salle

Dimmit

TILDEN

CATARINA

McMullen

Murphy Acreage

Area	Net Acres	Reservoir	Inter-Well Spacing (ft)	Gross Remaining Wells*
		Lower EFS	300	121
Karnes	10,918	Upper EFS	700	159
		Austin Chalk	700	108
		Lower EFS	500	388
Tilden	64,737	Upper EFS	500	140
		Austin Chalk	600	100
		Lower EFS	450	292
Catarina	47,653	Upper EFS	600	354
		Austin Chalk	800	149
Total	123,308			1,811

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Eagle Ford Shale

Well Delivery Update

2019 Well Delivery Plan

• 91 wells online

3Q 2019 51 MBOEPD, 80% Oil, 91% Liquids

• >15% increase in volumes from 2Q 2019
• 25 wells online, 91% liquids
• • 15 Catarina - 11 Lower EFS, 4 Upper EFS
  • 10 Tilden - Lower EFS

4Q 2019, 18 Wells Online

• 8 Tilden - Lower EFS
• 10 Catarina - 9 Lower EFS, 1 Upper EFS

Eagle Ford Shale Acreage

	Wilson	KARNES
	Atascosa
		Karnes
Zavala	Frio
	TILDEN
CATARINA
Dimmit
	La Salle	Bee
	Live Oak
	McMullen

Murphy Acreage

Consistently Increasing EURs	EUR per Well MBOE by Year
• Improved well targeting	750

• Optimized completion design

• Resulting in higher oil cut and IP rates	500			584
			499		528
Achieving Lower OPEX			429

• <$7/BOE 3Q 2019

• >18% reduction from 2Q 2019	250
2016	2017	2018		2019
NOTE: EFS = Eagle Ford Shale				Interquartile Range		Median
NOTE: Interquartile range shows difference between 75th and 25th percentile of well EURs
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Eagle Ford Shale

Well Outperformance in Tilden and Catarina

Tilden - 10 Tyler Ranch Wells Online	Tilden New Well Performance Cum MBOE
• 10 Lower EFS wells with avg 7,100' lateral	80
• 500' well spacing	60
• Average IP30 of 1,300 BOEPD	40
	20
	0
	0	10	20	30	40	50	60	70	80	90
					Days Online
		Tyler Ranch Average LEFS		Tyler Ranch LEFS Average Type Curve
Catarina - 11 Stumberg Wells Online	Catarina New Well Performance Cum MBOE

• 9 Lower EFS wells with avg 7,800' lateral

80

• • 350' well spacing
  • Lower EFS wells peak IP 1,400 BOEPD average
• 2 Upper EFS wells with avg 8,800' lateral
• • 1,200' well spacing
  • Performing to type curve

60

40

20

0

0	10	20	30	40	50	60	70	80	90
				Days Online

		Stumberg Average LEFS	Stumberg LEFS Average Type Curve
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Kaybob Duvernay

Scalable Assets For Future Growth

Oil-Weighted Production from Low Cost

Kaybob Duvernay Acreage

Assets				Kaybob North
•	Approaching completion of retention drilling
		Kaybob East
•	Optimizing development plan and lateral lengths					Two Creeks
• Continuing outperformance with high rate wells	Simonette
• Targeting $6.5 MM per well drilling and		Kaybob West
	completions costs
			Inter-Well	Remaining	Saxon
	Area	Net Acres	Spacing (ft)	Wells
	Two Creeks	34,336	984	123
	Kaybob East	36,400	984	182
	Kaybob West	25,760	984	119
	Kaybob North	31,360	984	129				0	Miles	10
	Simonette	29,715	984	82		Battery
	Saxon	12,746	984	37	Murphy Acreage	Facility	Pipeline

Total

170,317

672

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Kaybob Duvernay

Well Delivery Update

2019 Well Delivery Plan Complete

• 10 wells online in Kaybob Duvernay

3Q 2019 Results

• Kaybob Duvernay: 11 MBOEPD, 69% liquids
• • >18% increase in volumes from 2Q 2019

Kaybob Duvernay Land Retention Plan

• Drilling 16 wells in 2019, completions in 2020

2019 Online Wells

Area	Pad	Wells Online	IP30	Liquids
(BOEPD)
Simonette	08-03	3	1,400*	86%
Kaybob North	05-23	2	1,054	86%
Two Creeks	05-19	2	651*	91%
Two Creeks	16-29	2	858*	91%
Kaybob North	16-25	1	834*	85%

Strong Results in Kaybob Duvernay

• Recent well performance mirrors Tilden Lower EFS
• • Leveraged learnings to optimize completions design, resulting in EUR improvement
• High-gradinglocations across contiguous acreage
• Drilled pacesetter well: 12.5 days, $2.4 MM
• • In line with Eagle Ford Shale drilling rates
  • 9,700' lateral length

2019 Kaybob New Well Performance vs Eagle Ford Shale - Tilden LEFS

Cum MBOE

120

100

80

60

40

20

0

0	30	60	90	120	150	180
			Days Online

		2019 Kaybob Wells Average	Tyler Ranch LEFS Average Type Curve
* Well volumes constrained due to current facility limitations.
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Canada Onshore

Tupper Montney Update

2019 Well Delivery Plan Complete

• 8 wells online

3Q 2019 45 MBOEPD, 100% Natural Gas

• >20% increase in volumes from 2Q 2019
• New wells trending in line with 18 BCF type curve

		Mitigating AECO Exposure
	3Q 2019 Tupper Montney Natural Gas Sales
Dawn Price Exposure	AECO Price Exposure
Malin Price Exposure		4%
	53%
		7%

Chicago Price Exposure

15%

22%

Hedged

Successful AECO Price Mitigation

• • Realized 3Q 2019 C$1.61/MCF* vs AECO realized average of C$0.99/MCF
  • Projected FY19 C$2.26/MCF* vs AECO realized average of C$1.71/MCF
• C$0.27 transportation cost to AECO not subtracted

Tupper Montney Natural Gas Realizations 3Q 2019 $CAD/MCF

* C$0.27 of transportation cost not subtracted

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Offshore Portfolio Update

Gulf of Mexico

Free Cash Flow Generating Assets

Revitalized Portfolio

• Top 5 Gulf of Mexico operator by production
• Achieves high margin EBITDA/BOE
• Generating ongoing synergies from acquisitions
• Long runway for further development projects

	PRODUCING ASSETS
Asset	Operator	Murphy WI1
Cascade	Murphy	80%
Chinook	Murphy	53%
Clipper	Murphy	80%
Cottonwood	Murphy	80%
Dalmatian	Murphy	56%
Front Runner	Murphy	50%
Habanero	Shell	27%
Kodiak	Kosmos	48%
Lucius	Anadarko	9%
Marmalard	Murphy	27%
Marmalard East	Murphy	70%
Medusa	Murphy	48%
Neidermeyer	Murphy	53%
Powerball	Murphy	75%
Son of Bluto II	Murphy	27%
St. Malo	Chevron	20%
Tahoe	W&T	24%
Thunder Hawk	Murphy	50%

Gulf of Mexico Assets

Neidermeyer

Dalmatian

VK DD

	Delta House	Marmalard
	Son of Bluto II
		Calliope
Powerball	Medusa

		Nearly Headless Nick
EW	Kodiak	MC DC
	Ourse
Habanero
Front Runner

Khaleesi/Mormont

Samurai

GB

GC

AT LL

KC

WR

LU HE

Cascade/Chinook

Cascade

Chinook

Lucius

St. Malo

Murphy Assets

Offshore Platform

FPSO

Note: Anadarko is a wholly-owned subsidiary of Occidental Petroleum 1Excluding noncontrolling interest

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Gulf of Mexico

3Q 2019 Update

3Q 2019 Production 78 MBOEPD, 85% Liquids

• Operated production exceeded guidance

Dalmatian DC4 #2 Well

• Well drilled and completed, online 3Q 2019
• Online rate ~5,400 BOEPD gross

Nearly Headless Nick

• Completing well tie-in activities, online 4Q 2019

Medusa Rig Program

• Well workover complete, rig demobilized

King's Quay Floating Production System

• Construction underway
• Pursuing sell-down opportunities

St. Malo Waterflood Project Sanctioned

Front Runner SPAR

• Forecast to increase total EUR by 30 - 35 MMBOE1 net to Murphy

1 Contingent resources

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Gulf of Mexico

Project Execution Update

Short Term Project Update

• Working through planning and engineering
• • 3 tie-back projects
  • 1 well workover

Long Term Project Update

• Khaleesi / Mormont subsea engineering and construction contracts to be awarded in near-term
• Samurai pre-FEED work ongoing
• • Contracts bid jointly with Khaleesi / Mormont

Short Term Projects

	Planning &	Drilling &
Project	Engineering	Completions	Subsea Tie-In	First Oil
Dalmatian DC4 #2	✔	✔	✔	✔
Nearly Headless	✔	✔	✔	4Q 2019
Nick
Medusa	✔	✔	n/a	4Q 2019
Cottonwood	Ongoing	1Q 20201	n/a	2Q 2020
Calliope	Ongoing	✔	3Q 2020	4Q 2020
Ourse	Ongoing	3Q 20202	1H 2021	2H 2021
Son of Bluto II	Ongoing	2H 20212	2H 2021	4Q 2021

Long Term Projects

			Planning &	Drilling &
		Project	Engineering	Completions	Subsea Tie-In	First Oil
		Khaleesi / Mormont	Ongoing	4Q 2020 - 4Q 20212	2021	1H 2022
		Samurai	Ongoing	4Q 2020 - 4Q 2021	2021	1H 2022
		St. Malo Waterflood	Ongoing	2Q 2020 - 2Q 2021	2022	2023
1	Well workover. No drilling/completions activities.
2	Completion only. Well previously drilled. Khaleesi / Mormont 4 of 5 wells previously drilled.

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Gulf of Mexico

Short Cycle Capital Projects Deliver Accelerated Returns

Gulf of Mexico Short Cycle Projects

	Completions
New Wells	& Tie-Backs	Workovers
Dalmatian DC4 #2	Nearly Headless Nick	Cottonwood
Son of Bluto II	Ourse
	Calliope

21	$7.50CAPEX	>80
MMBOE	/BBL		% IRR
Total Net		Average
Resources			Project

WTI $55/BBL, 2019-2023

Net CAPEX $MM

50

40

30

20

10

0

2019Q2

2019Q3

2019Q4

2020Q1

2020Q2

2020Q3

2020Q4

2021 FY

Dalmatian

Cottonwood

NHN

SOB II

Calliope

Ourse

Development Timeline

2019	2020
Dalmatian	Son of Bluto II
Nearly Headless Nick	Ourse
	Calliope
	Cottonwood

Net Production MBOEPD

12
10
8										Production Generated through 2040
6
4
2
0
4Q 2019	2020	2021	2022	2023	2024	2025	2026	2027	2028	2029
		Dalmatian			Cottonwood		Nearly Headless Nick		Son of Bluto II		Calliope		Ourse

Production volumes may vary based on timing and performance

Production volumes, reserves and financial amounts exclude non-controlling interest

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Gulf of Mexico

Investing in Long Term High-Margin Projects

Khaleesi / Mormont
• Gross resource ~165 MMBOE, 90% liquids	Development Timeline
• 7 development wells planned - 4 previously drilled
• IRR >30%, NPV >$300 MM			2019		2020			2021			2022
Samurai							Subsea Development
• Gross resource ~60 MMBOE, 90% liquids						Drilling & Completion		1H 2022
• Potential upside ~15 MMBOE
											First Oil
• 4 development wells planned
• IRR >35%, NPV >$200 MM
WTI $55/BBL, 2019-2023
Net CAPEX $MM				Net Production MBOEPD
300				25
250				20					Production Generated through 2042
200				15
150				10
100				5
50				0
0				2022	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032
						Khaleesi / Mormont	Samurai
2019	2020	2021	2022	2023
	Khaleesi / Mormont	Samurai	Production volumes may vary based on timing and performance
				Production volumes, reserves and financial amounts exclude non-controlling interest
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Gulf of Mexico

Generating Long Term Free Cash Flow

Capital Commitments Support Long Term Growth	2019 - 2023 Estimated Gulf of Mexico Production MBOEPD
• Sanctioned St. Malo waterflood project 3Q 2019

• Maintaining $325 MM average CAPEX 2019 - 2023 assuming		85					85
	King's Quay sell down		90
•	Affirming 2019 CAPEX guidance						9	4
	80
• Producing 85 MBOEPD average from 2019 - 2023
			14
• Delivering sustainable cash flow from large inventory of
70
	development projects
					60		58
		Gulf of Mexico CAPEX
	Short-Cycle Tiebacks	2019-2023		50
				St. Malo	40
				Waterflood
			10%
			26%		30
			$325 MM		20
		32%
	Major Projects	Average
			10
				Development Projects,	-
			32%	Rig Programs & Workovers
				2019E Annualized	Base	Dev. Projects,	Major Projects	Short-Cycle	2019-2023
						Production	Production	Rig Programs		Tiebacks	Average
								& Workovers

CAPEX from Major Projects include Samurai and Khaleesi / Mormont

St. Malo waterflood CAPEX includes $50 MM carry for Petrobras Americas Inc.

Production volumes, sales volumes, reserves and financial amounts exclude non-controlling interest, unless otherwise stated.

2019E Annualized Production assumes full year impact of acquired assets in LLOG transaction. Production from Major Projects includes St. Malo waterflood, Samurai and Khaleesi / Mormont.

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Exploration Update

Exploration Strategy Overview

Focused & Meaningful

• Four primary exploration areas
• 3 to 5 exploration wells per year
• ~$100 MM/year

Reduced Risk

• Proven oil provinces
• Targeting appropriate working interest
• Leveraging strategic partnerships

Strategic Themes

• Consistent US Gulf of Mexico program
• Field extension and exploration in Vietnam
• Company-makingpotential from Brazil and Mexico
• Targeting <$12/BBL full-cycle finding and development cost

Exploration Core Focus Areas

GULF OF MEXICO

VIETNAM

BRAZIL

AUSTRALIA

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	NYSE: MUR

Exploration Update

Increasing Position in Sergipe-Alagoas Basin, Brazil

Asset Overview

Sergipe-Alagoas Basin

• Murphy 20%, ExxonMobil 50% (Op), Enauta Energia S.A. 30%
• Hold WI in 6 blocks, spanning ~1.1 MM acres
• >1.2 BN BOE reserves discovered nearby
• Successfully bid on 3 adjacent blocks in 3Q 2019
• • Blocks SEAL-M-505,SEAL-M-575 and SEAL-M-637
  • Added ~560,000 acres to position

Continuing to Evaluate Data

• Progressing seismic program and interpretation
• Providing long-term exploration upside

BRAZIL

Current WI Block

3Q Bid Block

Petrobras-Operated Block

Discovered Field

	351
	428	430
501	503	505

1. 575

Kilometers

0		50

All blocks begin with SEAL-M

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	NYSE: MUR

Exploration Update

Entering Potiguar Basin, Brazil

Asset Overview

• Murphy 30% WI, Wintershall Dea 70% (Op)
• Farm-inagreement to 3 blocks signed 3Q 2019
• • Blocks POT-W-857,POT-W-863 and POT-W-865
  • Total ~774,000 gross acres
• Proven oil basin in proximity to Pitu oil discovery
• Independent to Murphy's position in Sergipe- Alagoas Basin
• 3D seismic program in progress

Potiguar Basin

								Murphy WI Block
								Other Block
								Discovered Field
								Kilometers
Petrobras/BP/
	0			50
GALP/IBV
		Petrobras/BP/
		GALP

Petrobras/BP/	Petrobras	Petrobras/BP/
GALP/IBV	GALP
	Petrobras/	Petrobras/
	BP/GALP	BP/GALP
		POT-W-857	Petrobras/	POT-W-863POT-W-865
		Pitu	Shell

Shell

Petrobras/

Shell

BRAZIL

January 2020		w w w . m u r p h y o i l c o r p . c o m	28
	NYSE: MUR

Exploration Update

Salinas-Sureste Basin, Mexico

Block 5 Overview

• Increased working interest to 40% at low cost
• • Murphy 40% (Op), Petronas 30%, DEA 30%
• 34 leads / prospects
• Mean to upward gross resource potential:
• • 800 MMBO - 2,000 MMBO
• Planning additional exploration program in 2020

Cholula 1-EXP Highlights

• ~$12 MM net drilling costs
• Drilled to total depth (TD) of 8,825 feet
• Discovered 185 feet net hydrocarbon pay
• • Validates block potential
  • De-risksUpper Miocene play in SE corner of Block 5
• ~200 MMBOE of resources within tie-back distance

Salinas-Sureste Basin

Block 5

Cholula

MEXICO

Kilometers

0 60

		Murphy WI Block			Other Blocks			Discovery
			January 2020		w w w . m u r p h y o i l c o r p . c o m	29
				NYSE: MUR

Vietnam Update

Cuu Long Basin, Vietnam

Asset Overview

• Murphy 40% (Op), PVEP 35%, SKI 25%
• >400 MMBOE remaining resource potential on initial block (15-1/05)

Block 15-1/05 - Lac Da Vang (LDV) Field

• Received Prime Minister approval for LDV field outline development plan
• Commenced front-end engineering design work
• Continuing post-well analysis of LDT-1X discovery well
• • Potential to add bolt-on resources to LDV field development

Block 15-2/17

• Received Prime Minister approval on production sharing contract
• Formal contract signed 4Q 2019

Cuu Long Basin

VIETNAM

Block 15-2/17

Miles

010

Murphy WI Block

Block 15-1/05

LDT Discovery

LDN Discovery	LDV
Discovery

HSB Discovery

Murphy Block Discovery

Other Discovery / Producing Field

January 2020		w w w . m u r p h y o i l c o r p . c o m	30
	NYSE: MUR

Looking Ahead

Executing 2019 Goals

	POST-MALAYSIA TARGETS		ACHIEVING GOALS
$300	ACCOMPLISHING	$	Oct. 2019
		SHARE	500	Completed
	MILLION	REPURCHASE
		MILLION
200	DELIVERING 4Q 2019	202	On Track
4Q 2019
PRODUCTION RATE
	MBOEPD		MBOEPD
68%	GENERATING	67	As of 3Q 2019
LIQUIDS-WEIGHTED	%
PRODUCTION
>95%	REALIZING SALES	>94%	As of 3Q 2019
VOLUMES AT
PREMIUM TO WTI

All while maintaining our cash position 2018 - 2019

January 2020		w w w . m u r p h y o i l c o r p . c o m	32
	NYSE: MUR

Executing on Long-Term Plan

Maintaining >65% Liquids Production Weighting

• Plan flexible to maintain cash flow / CAPEX parity including dividend

US Onshore - Focusing on Oil-Weighted Growth

Canada Onshore - Scalable Based on Market Conditions

• Focused on lease retention

NA Offshore - Maintaining Current Production

• Consistent free cash flow business
• Short-cycletiebacks and development projects at existing facilities
• St. Malo waterflood, Khaleesi / Mormont and Samurai projects included

Annual Average Capital Spend

2019 - 2023

Exploration

Canada Onshore

7%

US Onshore

15%

$1.4 BN 52%

26%

WH Offshore

Exploration - Dedicated Strategy

• CAPEX ~$100 MM per year, flexible as needed
• Ongoing plan of 3-5 wells annually
Production volumes, sales volumes, reserves and financial amounts exclude non-controlling
interest, unless otherwise stated
January 2020		w w w . m u r p h y o i l c o r p . c o m	33
	NYSE: MUR

Positioning Company for Long-Term Value Creation

	TRANSFORMING		PRODUCING		RAMPING
	Portfolio by adding oil-weighted,		Oil-weighted assets that		High value Eagle Ford Shale
	high-margin assets		realize premium pricing		production
	EXECUTING		OFFERING		FOCUSING
	Short cycle Gulf of Mexico field		Investors exploration upside		On shareholder priorities
	development projects

January 2020		w w w . m u r p h y o i l c o r p . c o m	34
	NYSE: MUR

GOLDMAN SACHS GLOBAL ENERGY CONFERENCE

JANUARY 2020

ROGER W. JENKINS

PRESIDENT& CHIEF EXECUTIVE OFFICER

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.

January 2020		w w w . m u r p h y o i l c o r p . c o m	37
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4Q 2019 Guidance

Producing Asset	Liquids	Gas	Total
(BOPD)	(MCFD)	(BOEPD)
US - Eagle Ford Shale	48,300		31,300	53,500
Gulf of Mexico excluding NCI1	72,700		73,600	85,000
Gulf of Mexico including NCI	84,800		78,700	98,000
Canada - Tupper Montney	-	264,000	44,000
Kaybob Duvernay and Placid Montney	6,700		22,500	10,500
Offshore	8,400		-	8,400
Other	600		-	600
4Q Production Volume (BOEPD) excluding NCI 2	198,000 - 206,000
4Q Production Volume (BOEPD) including NCI	210,700 - 219,300
4Q Exploration Expense ($MM)	$21
Full Year 2019 CAPEX ($BN) excluding NCI 3	$1.35 - $1.45
Full Year 2019 Production (BOEPD) excluding NCI 4	174,000 - 178,000

1 Excludes Noncontrolling Interest of MP GOM of 12,100 BOPD liquids and 5,100 MCFD gas 2 Excludes Noncontrolling Interest of MP GOM of 13,000 BOEPD

3 Excludes Noncontrolling Interest of MP GOM of $48 MM and $20 MM for assets held for sale 4 Excludes Noncontrolling Interest of MP GOM of 12,600 BOEPD

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2019 Hedging Positions

United States
Commodity	Type	Volumes	Price	Start Date	End Date
(BBL/D)	(BBL)
WTI	Fixed Price Derivative Swap	35,000	$60.51	10/1/2019	12/31/2019
WTI	Fixed Price Derivative Swap	45,000	$56.42	1/1/2020	12/31/2020

Montney, Canada

Commodity	Type	Volumes	Price	Start Date	End Date
(MMCF/D)	(MCF)
Natural Gas	Fixed Price Forward Sales at	59	C$2.81	10/1/2019	10/31/2019
	AECO
Natural Gas	Fixed Price Forward Sales at	97	C$2.71	11/1/2019	3/31/2020
	AECO
Natural Gas	Fixed Price Forward Sales at	59	C$2.81	4/1/2020	12/31/2020
	AECO

* As of October 30, 2019

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Current Financial Position

As of September 30, 2019

• $2.8 BN total debt, excluding capital leases	Note Maturity Profile $MM

•	Total liquidity $2.0 BN		2,000
•	Approximately $435 MM of cash and cash
	equivalents
• Undrawn $1.6 BN unsecured senior credit facility	1,500
• 33% total debt to cap
•	28% net debt to cap
			1,000
	Maturity Profile*
	Total Bonds Outstanding $BN	$2.8	500
	Weighted Avg Fixed Coupon	5.5%										10 Year
	Weighted Avg Years to Maturity	7.0																				20 Year						30 Year
			0																												>2046
			2019	2020	2021	2022	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033	2034	2035	2036	2037	2038	2039	2040	2041	2042	2043	2044	2045	2046
														Notes		Undrawn RCF
* As of September 30, 2019
															January 2020		w w w . m u r p h y o i l c o r p . c o m		40
																NYSE: MUR

Effective Governance Underpins Long-Term Financial Strength

Expert and Independent Board

ESG Oversight

75%

ISS Governance

Score

Long-term industry, operating, and HSE expertise

Separate CEO and Chairman

12 out of 13 directors are independent

Board of Directors elected with average vote of 99% over past 5 years

Health, Safety and Environmental Committee established in 1993

• Worldwide HSE policy and management system applied to every employee, contractor and partner

Safety and environmental metrics in annual incentive plan performance since 2008

Climate change oversight

• Emissions forecasting in long-term planning
• Developed guiding principles for climate change

vs peer average

January 2020		w w w . m u r p h y o i l c o r p . c o m	41
	NYSE: MUR

Mitigating Risk Through Sustainable Environmental Operations

Safe Operations	Spills Management	GHG Emissions Reduction

1. average TRIR over past 4 years (vs

1. average for US E&P companies*)

Eagle Ford Shale well work 5 years lost time accident free

Vietnam seven years recordable free

Zero International Oil and Gas Producers (IOGP) recordable spills 1H 2019

Gulf of Mexico spill free since 2014

Asset integrity focus across life-cycle, leading to significant reduction in spills

28% reduction from 2015 to 2018

50% reduction with 2018-2019 acquisition and divestment activity

Long-term reductions with natural gas- fueled frac pumps in onshore Canada operations

A proud member of

The Environmental Partnership

Incident rate, spills rate, and emissions targets drive continual improvement

* Company reported data, sourced from Bloomberg

January 2020		w w w . m u r p h y o i l c o r p . c o m	42
	NYSE: MUR

Employee and Community Investments Support Stable Operations

Everywhere We Work	North America	International

Competitive employee benefits	El Dorado Promise
• Comprehensive health care coverage	• Tuition scholarship provided to El Dorado
•	Retirement savings plans	High School graduates
•	Education assistance program	• College enrollment rate surpasses state and
		national levels
Global Learning Management System	United Way
• ~300 professional development courses and
	more than 125 technical courses	• Partners for more than 50 years
		• Over $13 MM contributed in past 20 years

Process for new country entry

• Includes assessment of ESG risks

Social impact assessments

Community consultation processes

Prioritizing local suppliers

Threshold investment targets for local content

January 2020		w w w . m u r p h y o i l c o r p . c o m	43
	NYSE: MUR

Non-GAAP Reconciliation

ADJUSTED EARNINGS

Murphy defines Adjusted Earnings as net income attributable to Murphy1 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 accordance with generally accepted accounting principles (GAAP). Adjusted Earnings has certain limitations regarding financial assessments because 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.

	$ Millions, except per share amounts	Three Months Ended - Sept 30, 2019	Three Months Ended - Sept 30, 2018
	Net income attributable to Murphy (GAAP)	1,089.0		93.9
	Discontinued operations loss (income)	(953.4)		(37.8)
	Income from continuing operations	135.6		56.1
	Mark-to-market (gain) loss on crude oil derivative contracts	(38.9)		(20.6)
	Mark-to-market (gain) loss on contingent consideration	(22.4)			-
	Business development transaction costs	3.3			-
	Tax benefits on investments in foreign areas	(15.0)			-
	Write-off of previously suspended exploration wells	-		4.5
	Foreign exchange losses (gains)	0.8			-
	Ecuador arbitration settlement	-		(20.5)
	Brunei working interest income	-		(16.0)
	Seal insurance proceeds	(6.2)		(7.0)
	Adjusted Income (loss) attributable to Murphy (Non-GAAP)	57.2		(3.5)
	Adjusted income (loss) from continuing operations per diluted share	0.36		(0.02)
1 'Attributable to Murphy' represents the economic interest of Murphy excluding a 20% noncontrolling interest in MP GOM.
			January 2020		w w w . m u r p h y o i l c o r p . c o m		44
				NYSE: MUR

Non-GAAP Reconciliation

EBITDA and EBITDAX

Murphy defines EBITDA as income from continuing operations attributable to Murphy1 before interest, taxes, depreciation and amortization (DD&A). Murphy defines EBITDAX as income from continuing operations attributable to Murphy before interest, taxes, depreciation and amortization (DD&A) and exploration expense.

Management believes that EBITDA and EBITDAX 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 and 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). EBITDA and EBITDAX have certain limitations regarding financial assessments because they excludes certain items that affect net income and net cash provided by operating activities. EBITDA and EBITDAX should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.

$ Millions	Three Months Ended - Sept 30, 2019	Three Months Ended - Sept 30, 2018
Net income (loss) attributable to Murphy (GAAP)	1,089.0	93.9
Income tax expense (benefit)	18.8	17.8
Interest expense, net	44.9	44.2
DD&A expense	308.3	197.5
EBITDA attributable to Murphy (Non-GAAP)	1,461.0	353.4
Exploration expense	12.4	21.7
EBITDAX attributable to Murphy (Non-GAAP)	1,473.4	375.1
Total barrels of oil equivalents sold from continuing operations attributable to	17,745	11,232
Murphy (thousands of barrels)
EBITDAX per BOE (Non-GAAP)	83.03	33.39

1 'Attributable to Murphy' represents the economic interest of Murphy excluding a 20% noncontrolling interest in MP GOM.

January 2020		w w w . m u r p h y o i l c o r p . c o m	45
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Non-GAAP Reconciliation

ADJUSTED EBITDA

Murphy defines Adjusted EBITDA as income from continuing operations attributable to Murphy1 before interest, taxes, depreciation and amortization (DD&A), impairment expense, foreign exchange gains and losses, mark-to-market loss on crude oil derivative contracts, accretion of asset retirement obligations and certain other items that management believes affect comparability between periods.

Adjusted EBITDA is used by management to evaluate the company's operational performance and trends between periods and relative to its industry competitors.

Adjusted EBITDA 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). Adjusted EBITDA has certain limitations regarding financial assessments because it excludes certain items that affect net income and net cash provided by operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.

	$ Millions, except per BOE amounts	Three Months Ended - Sept 30, 2019	Three Months Ended - Sept 30, 2018
	EBITDA attributable to Murphy (Non-GAAP)	1,461.0		353.4
	Discontinued operations loss (income)	(953.4)		(37.8)
	Mark-to-market (gain) loss on crude oil derivative contracts	(49.2)		(26.0)
	Accretion of asset retirement obligations	10.6		6.5
	Business development transaction costs	4.1		-
	Write-off of previously suspended exploration wells	-		4.5
	Seal insurance proceeds	(8.0)		(9.7)
	Foreign exchange losses (gains)	0.8		(1.0)
	Mark-to-market (gain) loss on contingent consideration	(28.4)		-
	Ecuador arbitration settlement	-		(26.0)
	Brunei working interest income	-		(16.0)
	Adjusted EBITDA attributable to Murphy (Non-GAAP)	437.5		247.9
	Total barrels of oil equivalents sold from continuing operations attributable to Murphy	17,745		11,232
	(thousands of barrels)
	Adjusted EBITDA per BOE (Non-GAAP)	24.65		22.07
	1 'Attributable to Murphy' represents the economic interest of Murphy excluding a 20% noncontrolling interest in MP GOM.
			January 2020		w w w . m u r p h y o i l c o r p . c o m	46
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Glossary of Abbreviations

BBL: Barrels (equal to 42 US gallons)

BCF: Billion cubic feet

BCFE: Billion cubic feet equivalent

BN: Billions

BOE: Barrels of oil equivalent (1 barrel of oil or 6,000 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

EFS: Eagle Ford Shale

EUR: Estimated ultimate recovery

F&D: Finding & development

G&A: General and administrative expenses

GOM: Gulf of Mexico

LOE: Lease operating expense

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

1. Millions

MMBOE: Millions of barrels of oil equivalent

MMCF: Millions of cubic feet

MMCFD: Millions of cubic feet per day

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)

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Positioned for Investor Value Creation

$/BOE 1P Total Reserves

4.3% Dividend Yield

Longstanding & Competitive

28% Net Debt to Cap

At September 30, 2019

1.3x Net Debt / EBITDAX*

At September 30, 2019

* 3Q 2019 annualized adjusted EBITDAX

$25 $20 $15

$10	Median $8.76

$5$5.54

$0

Note: Calculated based on Market Cap (12/31/2019, in $Millions) Divided by Total Proved Reserves (MMBOE, 12/31/18);

Source: FactSet

Peer Group: APA, CLR, CXO, DVN, ECA, FANG, HES, MRO, NBL, PE, PXD, WPX, XEC

$/BOE 1P Oil Reserves

$45

$30

Median $18.86

$15 $10.28

$0

Note: Calculated based on Market Cap (12/31/2019), in $Millions) Divided by Total Proved Oil Reserves (MMBOE, 12/31/18);

Source: FactSet

Peer Group: APA, CLR, CXO, DVN, ECA, FANG, HES, MRO, NBL, PE, PXD, WPX, XEC

Value Per Flowing Oil Barrel

$150

$100

Median $61.94

$50$37.29

$0

Note: Calculated based on Market Cap (12/31/2019, in $Millions) Divided by 3Q 2019 Oil Production (MBOPD)

Source: FactSet

Peer Group: APA, CLR, CXO, DVN, ECA, FANG, HES, MRO, NBL, PE, PXD, WPX, XEC

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Eagle Ford Shale

Peer Acreage

OIL

CONDENSATE

GAS

Murphy

EOG

Lewis/BP ConocoPhillips

Marathon EP Energy

Pioneer

Encana

Carrizo Chesapeake

Sanchez

January 2020		w w w . m u r p h y o i l c o r p . c o m	49
	NYSE: MUR

Eagle Ford Shale

Murphy Spacing vs Peers

Karnes Typical Murphy Spacing

LEFS ~250-500'

EOG Offset Spacing

LEFS ~250' to 500'

DVN Offset Spacing

LEFS ~250' to 500'

COP Offset Spacing

LEFS ~250' to 600'

Murphy

BP

CHK Offset Spacing

LEFS ~350' to 1000'

MRO Offset Spacing

LEFS ~250' to 600'

Catarina Typical Murphy Spacing

LEFS ~300' to 600'

Tilden Typical Murphy Spacing

LEFS ~350' to 800'

CHK Offset Spacing

Chesapeake

Conoco

Devon

Encana

EOG

Equinor (Statoil)

Inpex (Gulftex)

Magnolia

Marathon

Pioneer

SE Offset Spacing

LEFS ~300' to 800'

Sanchez

LEFS ~ 250' to 300'

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Kaybob Duvernay

Peer Acreage

SHELL		KAYBOB EAST
		PARAMOUNT
ENCANA		CENOVUS
		KAYBOB WEST

KEYERA

SIMONETTE

SAXON

Fox Creek

CHEVRON

SEMCAMS

KAYBOB

XTO

PLACID

REPSOL

6 Miles

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Tupper Montney

Peer Acreage

Dawson

Creek

Other Competitor Montney Land

Open Crown - Montney

Murphy Montney Land

0	Miles	10

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Placid Montney

Peer Acreage

			KAYBOB EAST
HAMMERHEAD	TANGLE		PARAMOUNT
	CREEK	CNRL	CENOVUS
		ENCANA	KAYBOB WEST
KEYERA
SIMONETTE
			Fox Creek

SAXON CHEVRON

Condensate SEMCAMS

KAYBOB

Limit

DELPHIXTO

PLACID

Dry Gas

Limit	6 Miles

HAMMERHEAD

MONT

MONT

TANGLE CREEK

January 2020		w w w . m u r p h y o i l c o r p . c o m	53
	NYSE: MUR

GOLDMAN SACHS GLOBAL ENERGY CONFERENCE

JANUARY 2020

ROGER W. JENKINS

PRESIDENT& CHIEF EXECUTIVE OFFICER