Murphy Oil : Q4 2019 Earnings Presentation

2019

FOURTH QUARTER EARNINGS

CONFERENCE CALL & WEBCAST

JANUARY 30, 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; or 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". 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]

January 2020		www. m u rp h yo i l c o rp . c o m	1
	NYSE: MUR

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 173 MBOEPD in

94% oil volumes sold at

Returned >$660 MM to

Closed Gulf of Mexico and

Brought 91 operated wells

FY 2019, ~60% oil

premium to WTI in FY 2019

shareholders in FY 2019

Malaysia transactions

online in Eagle Ford Shale

Increased Gulf of Mexico

Adjusted EBITDA $404 MM

Completed $500 MM

Transformed into a top 5

Sanctioned several Gulf of

production >200% from

4Q 2019

share buyback program

Gulf of Mexico operator

Mexico projects set to deliver

FY 2018

$23 adj. EBITDA/BOE

Delivered 4% dividend yield

by production

sustainable FCF

Increased Eagle Ford Shale

4Q 2019

Benefitted shareholders within

Issued Inaugural

Successfully completed multiple

production >23% from

Sustainability Report

workovers and tiebacks in Gulf

4Q 2018

Generated $145 MM of free

cash flow including sale

of Mexico on schedule

cash in FY 2019

proceeds

Added new blocks in Sergipe-

Accelerated oil-weighted growth

Alagoas and Potiguar basins

in long-term plan

in Brazil

Drilled successful wells in Gulf

of Mexico, offshore Mexico

and Vietnam

Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated

Free cash generated includes NCI

January 2020

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2019 Production Update

4Q 2019 and FY 2019 Production

4Q 2019 Production 194 MBOEPD, 67% Liquids	4Q 2019 Production
• >115,000 BOPD oil production		60% Oil
• Gulf of Mexico (3,500) BOEPD	33% Natural Gas
27%
• (1,500) BOEPD at Neidermeyer (Mississippi Canyon 209)	30%
194			Eagle Ford Shale
subsea equipment malfunction			Offshore
• (1,900) BOEPD extended non-operated downtime	MBOEPD			Canada Onshore

• Canada offshore (1,000) BOEPD
• • Extended non-operated downtime at Terra Nova
• Eagle Ford Shale (3,600) BOEPD
• • Workover activity on higher rate Catarina wells
  • New East Tilden wells outperforming historical rates but below current corporate forecast

FY 2019 Production 173 MBOEPD, 67% Liquids

• >103,000 BOPD oil production
• Increased oil volumes 14% from FY 2018
• 57% onshore, 43% offshore

7% NGL	43%

FY 2019 Production

33% Natural Gas	60% Oil
31%	26%
		Eagle Ford Shale
173
		Offshore
MBOEPD			Canada Onshore

7% NGL

Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated FY 2018 oil volumes include contribution from Malaysia assets

43%

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Maintaining High-Margin Reserves in 2019

• Sustaining 50% oil-weighted portfolio
• Organic reserves replacement 172%
• Increased proved developed reserves from 50% to 57% year-over-year
• 3-yearaverage total F&D cost of $12.95/BOE
• Reserve life index of 11.8 years

2019E Proved Reserves

38%		36%
800	43%	57%	50%
	MMBOE		Liquids-Weighted

	26%					7%
US Onshore		Offshore		Canada Onshore		Oil		NGL		Natural Gas

Proved Reserves MMBOE

Malaysia divestment of 121 MMBOE excludes 7 MMBOE attributable to production

Lowering 3-Year Average Organic F&D Costs $/BOE

$20

$15

$10

$5

$0

2016

2017

2018

2019

Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated

Reserves are based on preliminary SEC year-end 2019 audited proved reserves and exclude noncontrolling interest

January 2020		www. m u rp h yo i l c o rp . c o m	4
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4Q 2019 Financial Results

4Q 2019 Results

• Net loss $72 MM
• Adjusted net income $25 MM

4Q 2019 Accounting Adjustments

• One-offincome adjustments after-tax:
• • MTM loss on crude oil derivatives $106 MM
  • MTM loss on contingent consideration $7 MM
  • Loss on extinguishment of debt $25 MM

4Q 2019 ($MM Except Per Share)

Net Income Attributable to Murphy

Income (loss)	($72)
$/Diluted share	($0.46)
Adjusted Income from Cont. Ops.
Adjusted income (loss)	$25
$/Diluted share	$0.16

Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated

January 2020		www. m u rp h yo i l c o rp . c o m	5
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Maintaining Financial Discipline & Balance Sheet Strength

4Q 2019 Cash Flow from Continuing Operations

• Cash flow exceeded property additions and dry hole costs by $1 MM
• $57 MM working capital increase
• $16 MM non-cashlong-term compensation

Other Highlights

• Completed $500 MM share repurchase program
• Issued $550 MM of 5.875% senior notes due 2027
• • Proceeds used to repurchase aggregate $521 MM of senior notes due 2022

Cash Flow Attributable to Murphy ($MM)	4Q 2019	FY 2019
Net cash provided by continuing operations	$336	$1,489
Property additions and dry hole costs	($335)	($1,344)
Free Cash Flow	$1	$145

Adjusted EBITDA Attributable to Murphy ($MM)	4Q 2019	FY 2019
EBITDA attributable to Murphy	$289	$2,460
Discontinued operations (income)	($37)	($1,065)
Mark-to-market loss on crude oil derivatives contracts	$142	$42
and contingent consideration
Other	$10	$77
Adjusted EBITDA	$404	$1,514

• Net debt / annualized adjusted EBITDAX of 1.5x at 4Q 2019

Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated

Free cash flow includes NCI

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Achieving Premium Oil-Weighted Realizations

>112,000BBLS/Day 95%SOLD

SOLD 4Q 2019At Premium

to $56.96 WTI

Sales Volumes & Differential Basis

	Eagle Ford		North America		4Q 2019 Total Company
	Shale		Offshore	Other - Onshore Canada
						33%	Mars - GOM
EBITDA/BOE	$31/BOE		$30/BOE	Brent - Offshore Canada	5%		+$1.31/BBL
	+$5.54/BBL	6%
4Q 2019
			Differentials
FIELD-LEVEL
						vs
				HLS - GOM		$56.96 WTI
				+$4.32/BBL	22%		MEH - Eagle Ford
							+$3.10/BBL

34%

Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated

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Accelerating Returns to Shareholders

Disciplined and Flexible Strategy

Free Cash Flow ($MM) 2019E

• Returned >$660 MM cash in 2019
• • >$500 MM in share repurchases
  • Repurchased 12% of shares outstanding
• Generated free cash flow1 in 2019
• No equity issuances

$600 $400 $200 $0 -$200-$400-$600-$800-$1,000

• Delivered industry leading dividend yield
• Returned >$3.9 BN cash since 2012

Note: FCF = 2019E Median Consensus Cash Flow from Operations less Annual CAPEX at 1/28/2020

Source: FactSet

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

• • Repurchased >$1.8 BN shares since 2012
  • >22% of shares outstanding
• Continued focus on generating cash flow in excess of capital spending and dividends

1 Free cash flow calculated as cash flow from operations less annual CAPEX, excluding proved property additions and including noncontrolling interest

Dividend Yield

4%

3%

2%

1%

0%

Source: FactSet at 1/28/2020

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

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Effective Governance Supports Long-Term Financial Strength

Expert and Independent Board

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

ESG Management

75%

ISS Governance Score

vs Peer Average

Health, Safety and Environmental

Committee established in 1994

• 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 focus

• Emissions forecasting in long-term planning improves full-cycle asset management
• Developed guiding principles for climate change

January 2020		www. m u rp h yo i l c o rp . c o m	9
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Mitigating Risk Through Sustainable Environmental Operations

Safe Operations	Environmental Management	GHG Emissions Reduction

0.36 average TRIR over past 5 years (vs	One IOGP** recordable spill in 2019,	50% reduction in GHG emissions
4-year average of 0.38 for US E&P	equaling rate of 1.2 BBLS per MMBOE	anticipated from 2018 - 2020
companies*)	Gulf of Mexico IOGP spill free since 2014	Potential for long-term reductions with
Eagle Ford Shale well work 5.5 years lost
	natural gas-fueled frac pumps in NA
time incident free	Recycle 100% of produced water in	Onshore
Gulf of Mexico 7.5 years lost time incident	Tupper Montney
free

Proud member of

Internal targets for incident rate, spill rate and emissions

drive continual improvement

• Company reported data as of FY 2018, sourced from Bloomberg
• IOGP - International Association of Oil & Gas Producers

January 2020		www. m u rp h yo i l c o rp . c o m	10
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Onshore Portfolio Update

Eagle Ford Shale

4Q 2019 and FY 2019 Update

FY 2019 45 MBOEPD, 76% Oil, 89% Liquids

• 91 operated, 9 non-operated wells online
• Increased oil weighting from 73% at FY 2018

4Q 2019 50 MBOEPD, 77% Oil, 89% Liquids

• Production increased >23% from 4Q 2018
• 18 wells online
• • 8 Tilden - Lower EFS
  • 10 Catarina - 9 Lower EFS, 1 Upper EFS

Lowered Drilling and Completions Costs

• <$6 MM average per well in FY 2019

Improved IP30 Rates in 2019

• Increased median IP30 oil rates >18% from 2018
• Increased median IP30 oil rates >50% from 2016

Eagle Ford Shale Acreage

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

Murphy Acreage

Rig on Location

EUR per Well MBOE by Year

750

584

500							499				528
250			429
2016	2017			2018		2019
					Interquartile Range		Median

Note: EFS = Eagle Ford Shale

Note: Interquartile range shows difference between 75th and 25th percentile of well EURs

January 2020		www. m u rp h yo i l c o rp . c o m	12
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Kaybob Duvernay

4Q 2019 and FY 2019 Update

FY 2019 10 MBOEPD, 54% Oil, 65% Liquids

• 16% production increase over FY 2018
• 10 wells online
• Well performance exceeded expectations by 17%

Kaybob Duvernay Acreage

Kaybob North

Kaybob East

4Q 2019 9 MBOEPD, 55% Oil, 68% Liquids

• 8 wells drilled for lease retention

Strong Results in 2019

• Drilled and completed lowest cost well <$6.3 MM
• Drilled longest lateral to-date >13,600'
•	Drilled fastest well to-date <12 days
•	Utilizing bi-fuel to reduce diesel costs and

Simonette

Kaybob West

Saxon

Two Creeks

greenhouse gas emissions
•	Achieved >30% CO2 reduction in emissions
•	Resulted in CAPEX savings

0 Miles 10

Murphy Acreage		Battery	Facility		Pipeline

January 2020		www. m u rp h yo i l c o rp . c o m	13
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Tupper Montney

4Q 2019 and FY 2019 Update

FY 2019 243 MCFD	Successful AECO Price Mitigation
•	8 wells online	• Realized FY19 C$2.15/MCF* vs AECO realized
•	Generated positive free cash for the year	average of C$1.64/MCF

4Q 2019 260 MCFD

• New wells trending in line with 24 BCF type curve

* C$0.29 transportation cost to AECO not subtracted

	Mitigating AECO Exposure	Tupper Montney Natural Gas Realizations FY 2019	$CAD/MCF
	FY 2019 Tupper Montney Natural Gas Sales
Dawn Price Exposure	AECO Price Exposure
Malin Price Exposure	4%	49%
	8%

Chicago Price Exposure

15%

24%

Hedged

* C$0.29 of transportation cost not subtracted

January 2020		www. m u rp h yo i l c o rp . c o m	14
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Offshore Portfolio Update

Gulf of Mexico

4Q 2019 Update

4Q 2019 Production 82 MBOEPD, 85% Liquids Nearly Headless Nick (Mississippi Canyon 387)

• Tie-inactivities completed, online 4Q 2019
• Peak gross rate 6,900 BOEPD

Chinook #5 (Walker Ridge 425)

• Workover completed, online 4Q 2019
• Peak gross rate 13,000 BOEPD

Medusa A6 (Mississippi Canyon 582)

• Workover completed, online 4Q 2019
• Peak gross rate 1,600 BOEPD

King's Quay Floating Production System

• Executed memorandum of understanding with ArcLight Capital Partners, LLC
• Negotiating final agreements detailing assumption of future capital requirements, as well as reimbursement of ~$125 MM previous capital outlay

Gulf of Mexico Assets

Neidermeyer	Dalmatian
Otis

VK DD

Delta House	Marmalard
Son of Bluto II

			Calliope
Powerball	Medusa
		Kodiak	Nearly Headless Nick
	EW	MC DC
		Ourse
Habanero
Front Runner
Samurai		Khaleesi/Mormont
GB	GC		AT LL
KC	WR		LU HE

	Cascade/Chinook	Cascade
		Chinook
Lucius		St. Malo

• Closing anticipated late 1Q to early 2Q 2019

Murphy Assets

Offshore Platform

FPSO

Note: Production volumes and financial amounts exclude noncontrolling interest, unless otherwise stated

January 2020		www. m u rp h yo i l c o rp . c o m	16
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Gulf of Mexico

Multi-Year Project Execution Update

Tieback & Workover Projects

• Multiple projects to sustain long-term production
• Timely execution of project schedule
• Platform and workover rigs currently on location

Major Project Update

Khaleesi / Mormont

• FEED engineering work complete
• Subsea engineering and construction contracts awarded

Samurai

• Pre-FEEDengineering work complete
• Subsea engineering and construction contracts awarded

Tieback & Workover Projects

	Planning &	Drilling &
Project	Engineering	Completions	Subsea Tie-In	First Oil
Front Runner Rig	✔	1Q -3Q 2020	n/a	2Q - 4Q 2020
Program - 3 Wells
Cascade #4	✔	1Q 20201	n/a	2Q 2020
workover
Dalmatian 134 #2	✔	1Q 20201	n/a	2Q 2020
workover
Calliope	Ongoing	✔	3Q 2020	4Q 2020
Ourse	Ongoing	2H 20212	2H 2021	4Q 2021
Son of Bluto II	Ongoing	2H 2021	2H 2021	4Q 2021

Major 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.

January 2020		www. m u rp h yo i l c o rp . c o m	17
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Looking Ahead

2020 Capital Program

	Production	181 - 193 MBOEPD
	1Q 2020	190 - 202 MBOEPD
	Production
	FY 2020
2020	CAPEX	$1.4 - $1.5 Billion
GUIDANCE	FY 2020

Focusing CAPEX on High Margin Assets

• $1.2 BN allocated to Eagle Ford Shale and offshore
• 92% allocated to field development and development drilling

Producing from our Oil-Weighted Portfolio

• 60% oil-weighted production in 2020
• 95% of oil forecasted at premium to WTI

2020 Total CAPEX

47%

1%

			US Onshore
7%			Offshore
		Canada Onshore
12%			Exploration
		Other
	33%

CAPEX by Production Year

2%

72%		2020 Production
		2021 Production

22%			2022+ Production
		Other
	4%

Generating Free Cash to Cover Dividend at $55 WTI

	Note: 2022+ production includes exploration and St. Malo waterflood, Khaleesi,
Note: Production volumes, sales volumes, reserves and financial amounts exclude noncontrolling interest, unless otherwise stated	Mormont and Samurai projects
	January 2020		www. m u rp h yo i l c o rp . c o m		19
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Gulf of Mexico

Sustaining Production Through Short-Cycle Projects

Delivering Free Cash Flow with Efficient	2020 Estimated Gulf of Mexico Production MBOEPD
Capital Spending	100
• Producing 86 MBOEPD in 2020	90		13	3	86
• $440 MM CAPEX in 2020	82
• Generating ~$1 BN in operating cash flow	80
	70
		70
Executing 2020 Gulf of Mexico Projects	60
• 6 operated wells online	50
• 3 platform-rig wells
•	2 workovers	40
•	1 subsea tieback	30
• 5 non-operated wells online
		20
		10
		-
		4Q 2019	Base	Operated Wells	Non-Operated	2020E Gulf of
Note: Assumes WTI $55/BBL	Production	Production		Wells	Mexico Prouction
Operated Wells includes Chinook 5 well online 4Q 2019
Production Volumes & Financial Amounts Exclude Non-Controlling Interest, Unless Otherwise Stated
				January 2020	www. m u rp h yo i l c o rp . c o m	20
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North America Onshore

Growing Eagle Ford Shale With Continued Investment

2020 Onshore Capital Budget $855 MM		Eagle Ford Shale Well Locations
• $680 MM Eagle Ford Shale												Inter-Well	Remaining
					Area	Net Acres	Reservoir		Spacing (ft)	Wells
	• 97 operated wells + 59 non-operated wells online							Lower EFS			300		99
• $125 MM Kaybob Duvernay						Karnes		10,101	Upper EFS			800		155
	• 16 operated wells online										Austin Chalk			1,200		102
										Lower EFS			500		354
• $35 MM Tupper Montney
					Tilden		64,756	Upper EFS			500		140
	• 5 operated wells online										Austin Chalk			600		100
• $15 MM Placid Montney						Catarina		48,384	Lower EFS			450		272
	• 11 non-operated wells online							Upper EFS			900		349
										Austin Chalk			1,200		149
2020 Wells Online										Total		123,241							1,720
70
60												Kaybob Duvernay Well Locations
50
																		Inter-Well	Remaining
40
												Area			Net Acres		Spacing (ft)	Wells
30													Two Creeks			34,784			984		137
20
												Kaybob East			37,744			984		158
10
												Kaybob West			25,984			984		106
0
												Kaybob North		27,328			984		135
	1Q 2020		2Q 2020	3Q 2020		4Q 2020
			Eagle Ford Shale			Eagle Ford Shale (Non-Op)		Kaybob Duvernay		Simonette			33,459			984		115
	Saxon			12,746			984		55
			Tupper Montney			Placid Montney (Non-Op)
													Total			172,045						706
Note: Non-op well cadence subject to change per operator plans
Average 24% WI for Eagle Ford Shale non-operated wells
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2020 Exploration Plan

Focusing on Core Growth Areas

Targeting >500 MMBOE in Annual Program

• $100 MM 2020 CAPEX

Mt. Ouray, US Gulf of Mexico

• Murphy 20% WI, non-operated
• Green Canyon 767
• Expected spud 2Q 2020

Cholula-2DEL Appraisal Well, Offshore Mexico

• Murphy 40% WI, operator
• Targeting 3Q-4Q 2020

Batopilas Prospect, Offshore Mexico

• Murphy 40% WI, operator
• Targeting 4Q 2020
• Targeting new, sub-salt play

Sergipe-Alagoas Basin, Brazil

• Murphy 20% WI, non-operated
• >1.2 BN BOE reserves discovered nearby
• Several prospects of material volume identified
• Well planning ongoing in 2020; drilling planned early 2021

US GULF OF MEXICO

OFFSHORE MEXICO
BRAZIL

January 2020		www. m u rp h yo i l c o rp . c o m	22
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Overview of Long Range Strategic Plan 2020 - 2024

Positioning Company for Long-Term Value Creation

Generates ~$1.4 BN in Free Cash Flow Over	Annual Average Capital Spend
		2020 - 2024
5 Years After Dividend	Exploration		US Onshore
Delivering Consistent Oil-Weighted Production		8%
• Maintain ~60% oil-weighting from 2020 - 2024
Canada Onshore	12%	54%
Average Annual CAPEX ~$1.3 BN			$1.3 BN
• 2020 is peak CAPEX in 5-year plan	WH Offshore	26%

Balancing Onshore / Offshore Portfolio

• Increasing US onshore production by 10-12% CAGR through organic growth

2020E - 2024E Production Growth MBOEPD

• Sustaining production levels through multiple	250
200
offshore development projects					Offshore
Exploration - Focused Strategy	150	Offshore
• CAPEX ~$100 MM per year, flexible as needed	100	US				US
			Onshore
• Ongoing plan of 3-5 wells annually		Onshore
50	CAN				CAN
					Onshore
		Onshore
	0
Note: Assumes WTI $55/BBL	2020E	US Onshore	Canada Onshore	2024E
Production Volumes & Financial Amounts Exclude Non-Controlling Interest, Unless Otherwise Stated
			January 2020	www. m u rp h yo i l c o rp . c o m	23
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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 sustainable future
	development projects

January 2020		www. m u rp h yo i l c o rp . c o m	24
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2019

FOURTH QUARTER EARNINGS

CONFERENCE CALL & WEBCAST

JANUARY 30, 2020

ROGER W. JENKINS

PRESIDENT& CHIEF EXECUTIVE OFFICER

Appendix

Appendix

Non-GAAP Reconciliation

Abbreviations

Guidance

Hedging Positions

Current Financial Position

Environmental, Social and Governance

January 2020		www. m u rp h yo i l c o rp . c o m	27
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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.

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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 - Dec 31, 2019	Three Months Ended - Dec 31, 2018
Net income (loss) attributable to Murphy (GAAP)	(71.7)	103.4
Discontinued operations loss (income)	(36.9)	(64.1)
(Loss) income from continuing operations	(108.6)	39.3
Mark-to-market (gain) loss on crude oil derivative contracts	105.5	(27.6)
Loss on extinguishment of debt	25.4	-
Impact of tax reform	(4.2)	(15.7)
Tax benefits on investments in foreign areas	-	(14.7)
Mark-to-market (gain) loss on contingent consideration	6.5	(3.8)
Foreign exchange losses (gains)	-	(8.8)
Impairment of assets	-	15.8
Adjusted Income (loss) attributable to Murphy (Non-GAAP)	24.6	(15.5)
Adjusted income (loss) from continuing operations per diluted share	0.16	(0.09)

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

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Non-GAAP Reconciliation

EBITDA and EBITDAX

Murphy defines EBITDA as net income attributable to Murphy1 before interest, taxes, depreciation and amortization (DD&A). Murphy defines EBITDAX as net income 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 - Dec 31, 2019	Three Months Ended - Dec 31, 2018
Net income (loss) attributable to Murphy (GAAP)	(71.7)	103.4
Income tax expense (benefit)	(24.0)	(35.0)
Interest expense, net	74.2	47.3
DD&A expense	310.1	199.6
EBITDA attributable to Murphy (Non-GAAP)	288.6	315.3
Exploration expense	19.5	32.5
EBITDAX attributable to Murphy (Non-GAAP)	308.1	347.8

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

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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 - Dec 31, 2019	Three Months Ended - Dec 31, 2018
EBITDA attributable to Murphy (Non-GAAP)	288.6	315.3
Discontinued operations loss (income)	(36.9)	(64.2)
Mark-to-market (gain) loss on crude oil derivative contracts	133.5	(35.0)
Accretion of asset retirement obligations	10.7	7.9
Foreign exchange losses (gains)	-	(10.2)
Mark-to-market (gain) loss on contingent consideration	8.2	(4.8)
Impairment of assets	-	20.0
Adjusted EBITDA attributable to Murphy (Non-GAAP)	404.1	229.0
Total barrels of oil equivalents sold from continuing operations attributable to	17,617	11,814
Murphy (thousands of barrels)
Adjusted EBITDA per BOE (Non-GAAP)	22.94	19.39

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

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Non-GAAP Reconciliation

ADJUSTED EBITDAX

Murphy defines Adjusted EBITDAX as income from continuing operations attributable to Murphy1 before interest, taxes, depreciation and amortization (DD&A), exploration expense, 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 EBITDAX is used by management to evaluate the company's operational performance and trends between periods and relative to its industry competitors.

Adjusted EBITDAX 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 EBITDAX has certain limitations regarding financial assessments because it excludes certain items that affect net income and net cash provided by operating activities. Adjusted EBITDAX 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 - Dec 31, 2019	Three Months Ended - Dec 31, 2018
EBITDAX attributable to Murphy (Non-GAAP)	308.1	347.8
Discontinued operations loss (income)	(36.9)	(64.2)
Accretion of asset retirement obligations	10.7	7.9
Mark-to-market loss (gain) on crude oil derivative contracts	133.5	(35.0)
Mark-to-market loss (gain) on contingent consideration	8.2	(4.8)
Foreign exchange losses (gains)	-	(10.2)
Impairment of assets	-	20.0
Adjusted EBITDAX attributable to Murphy (Non-GAAP)	423.6	261.5
Total barrels of oil equivalents sold from continuing operations attributable to	17,617	11,814
Murphy (thousands of barrels)
Adjusted EBITDAX per BOE (Non-GAAP)	24.05	22.14

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

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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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1Q 2020 Guidance

Producing Asset	Oil	NGLs	Gas	Total
(BOPD)	(BOPD)	(MCFD)	(BOEPD)
US - Eagle Ford Shale	32,100	5,400	30,400	42,600
- Gulf of Mexico excluding NCI1	69,600	5,500	77,000	87,900
Canada - Tupper Montney	-	-	240,000	40,000
- Kaybob Duvernay and Placid Montney	6,200	1,600	22,200	11,500
- Offshore	4,500	-	-	4,500
Other	500	-	-	500
1Q Production Volume (BOEPD) excl. NCI 1	181,000 - 193,000
1Q Exploration Expense ($MM)	$28
Full Year 2020 CAPEX ($BN) excl. NCI 2	$1.4 - $1.5
Full Year 2020 Production (BOEPD) excl. NCI 3	190,000 - 202,000

1 Excludes noncontrolling interest of MP GOM of 12,800 BOPD oil, 600 BOPD NGLs and 5,200 MCFD gas 2 Excludes noncontrolling interest of MP GOM of $62 MM and $3 MM for assets held for sale

3 Excludes noncontrolling interest of MP GOM of 12,600 BOPD oil, 600 BOPD of NGLs, and 5,600 MCFD gas

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2020 Hedging Positions

United States
Commodity	Type	Volumes	Price	Start Date	End Date
(BBL/D)	(BBL)
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	97	C$2.71	1/1/2020	3/31/2020
	AECO
Natural Gas	Fixed Price Forward Sales at	59	C$2.81	4/1/2020	12/31/2020
	AECO

* As of January 29, 2020

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Current Financial Position

As of December 31, 2019

• $2.8 BN total debt, excluding capital leases
• Total liquidity $1.9 BN
• $307 MM of cash and cash equivalents
• Undrawn $1.6 BN unsecured senior credit facility
• 34% total debt to cap
• 31% net debt to cap

Maturity Profile*

Total Bonds Outstanding $BN	$2.8
Weighted Avg Fixed Coupon	5.8%
Weighted Avg Years to Maturity	7.7

Note Maturity Profile $MM

2,000

1,500

1,000

500

10 Year

20 Year

30 Year

0

Notes Undrawn RCF

* As of December 31, 2019

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Employee and Community Investments Support Stable Operations

In the Workplace	In the Community

Human Capital Initiatives

• Reviewing pay equity annually across employee groups and the organization
• Offering training and development through a variety of platforms to empower employees individually and professionally
• Partnering with external organizations to target diverse talent pools

Employee Engagement

• Solicit ongoing feedback and increase employee engagement through Ambassador program
• Ongoing review of benefit enhancements to attract and retain top talent
• Support employee communications with company-wide quarterly town halls

Culture Assimilation

• Corporate culture affirmed through internal Mission, Vision, Values and behaviors program
• Employee performance reviews include alignment with corporate behavior policies

United States & Canada

• El Dorado Promise
• • Tuition scholarship provided to El Dorado High School graduates
  • Benefitted more than 2,600 students since inception
  • College enrollment rate surpasses state and national levels
• United Way
• • Partners for more than 50 years
  • Over $13 MM contributed in past 20 years across multiple locations
  • >90% employee participation company-wide

International

• Process in place for new country entry
• • Includes assessment of ESG risks and social impact
• Community consultation processes
• Supporting local suppliers and initiatives
• Threshold investment targets for local content

January 2020		www. m u rp h yo i l c o rp . c o m	37
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2019

FOURTH QUARTER EARNINGS

CONFERENCE CALL & WEBCAST

JANUARY 30, 2020

ROGER W. JENKINS

PRESIDENT& CHIEF EXECUTIVE OFFICER