SECOND QUARTER 2020...•2020 capex guidance reduced to $1.2 billion on strong execution and capital efficiency − 50% reduction vs. beginning of year capital budget − 2H20 spend

SECOND QUARTER 2020

August 5, 2020

Forward-Looking Statements and Other Matters

2

This presentation (and oral statements made regarding the subjects of this presentation) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including, without limitation: the Company's future capital budgets and allocations (including development capital budget and resource play leasing and exploration spend), future performance, free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production, guidance, cash margins, asset sales and acquisitions, oil growth, cost and expense estimates, cash flows, uses of excess cash, return of cash to shareholders, returns, leasing and exploration activities, future financial position, tax rates and other plans and objectives for future operations. Words such as “anticipate”, “believe”, “could”, “enter,” “estimate”, “expect”, “forecast”, “future”, “guidance”, “intend”, “line of sight,” “may”, “outlook”, “plan”, “positioned,” “potential”, “project”, “seek”, “should”, “target”, “will”, “would”, or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking.

While the Company believes its assumptions concerning future events are reasonable, a number of factors could cause actual results to differ materially from those projected, including, but not limited to: conditions in the oil and gas industry, including supply/demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the U.S. and Equatorial Guinea, including changes in foreign currency exchange rates, interest rates, inflation rates; actions taken by the members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia affecting the production and pricing of crude oil; and other global and domestic political, economic or diplomatic developments; capital available for exploration and development; risks related to the Company’s hedging activities; voluntary or involuntary curtailments, delays or cancellations of certain drilling activities; well production timing; liability resulting from litigation; drilling and operating risks; lack of, or disruption in, access to storage capacity, pipelines or other transportation methods; availability of drilling rigs, materials and labor, including the costs associated therewith; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the government or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations, requirements or initiatives, including initiatives addressing the impact of global climate change, air emissions, or water management; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company’s 2019 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at https://ir.marathonoil.com/. Except as required by law, the Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

This presentation includes non-GAAP financial measures, including operating cash flow before working capital, and pro-forma cash balance. Reconciliations of the differences between non-GAAP financial measures used in this presentation and their most directly comparable GAAP financial measures are available at https://ir.marathonoil.com/ in the 2Q20 Investor Packet.

https://ir.marathonoil.com/https://ir.marathonoil.com/

Maintaining Focus During Unprecedented TimesStrong results in a challenging environment

“Amid tremendous commodity volatility, our ongoing response to the COVID-19 global

pandemic, and a challenging year for our industry, we have remained focused on the

factors we can control: how we allocate capital, how we manage our cost structure, and

how we execute… Our differentiated capital efficiency is illustrated by a 2021 benchmark

maintenance scenario that we believe could deliver total Company oil production in-line

with 4Q20 at a free cash flow breakeven of approximately $35/bbl.”

Chairman, President, and CEO Lee Tillman

3

Capital Efficiency Outperforming on Differentiated Execution

Managing Cost

Structure

• Record low U.S. unit production costs during 2Q20 of $4.09 per BOE

• Successfully implemented cash cost reduction efforts and on track to realize

$260MM of savings in 2020, inclusive of 2Q20 severance payments

• Driving 17% annualized G&A reduction compared to 2019 and 25% annualized

G&A reduction compared to 2018

Successfully positioned for FCF at prices well below forward curve

4

Protecting Balance

Sheet and Liquidity

• Balance sheet strength remains top priority; $3.5B of liquidity at end 2Q20 and investment grade credit rating at all three rating agencies

• 2H20 free cash flow breakeven in low $30/bbl WTI range while protecting operational momentum into 2021

• Differentiated capital efficiency highlighted by 2021 FCF breakeven of ~$35/bbl for benchmark maintenance scenario on an unhedged basis; delivers oil production in-line with 4Q20 average (>170 MBOPD)

Reducing Capital

Expenditures

• Low 2Q20 capex of $137MM and strong 2Q20 total oil production of 197 MBOPD

on capital efficiency outperformance

• Reducing 2020 capital spending guidance to $1.2B and raising 2020 oil production guidance to 190 MBOPD at midpoint, inclusive of curtailments

• 2Q20 average completed well cost (CWC) per lateral foot down ~10% vs. 2019 average

• Expect 2H20 CWC per lateral foot to decline >20% vs. 2019 average

Lowering full year capex while protecting operational momentum

• 2020 capex guidance reduced to $1.2 billion on strong execution and capital efficiency

− 50% reduction vs. beginning of year capital budget

− 2H20 spend high-graded and concentrated in Eagle Ford and Bakken, prioritizing returns, free cash flow, and capital efficiency

− 2H20 wells to sales heavily weighted to 4Q20

• 2020 total oil production guidance raised to 190MBOPD at midpoint, inclusive of curtailments

− 2Q20 frac pause and wells to sales timing leads to 3Q20 production trough for U.S. oil production

− U.S. oil production on improving trend into 4Q20

− Enter 2021 with DUC (drilled but uncompleted) backlog optimized for operational needs

• 2020 Resource Play Exploration (REx) drilling program successfully completed

2020 Capital Program & Guidance Update

5

2020 Gross Wells to Sales by Quarter

Eagle Ford

Bakken

~90%

Wells to Sales Timing Drives 3Q20

Production Trough

0

40

Apr '20 May '20 Jun '20 Jul '20 Aug '20 Sep '20

0

100

1Q20 2Q20 3Q20e 4Q20e

Bakken and Eagle Ford

Other

2Q20 3Q20e

Total Company Cash Flow for 2Q20

• Ended 2Q20 with $522MM cash balance and undrawn revolving credit facility of $3.0B

• Pro-Forma July 3rd cash balance of $611MM after receipt of Alternative Minimum Tax

(AMT) Refund

• Significant 2Q20 working capital headwinds expected to normalize over 2H20

• 2H20 free cash flow breakeven in low $30/bbl WTI range

Ending cash balance impacted by working capital

1 Excludes $8MM of exploration costs other than well costs included within Capital Expenditures2 Includes $(74)MM of changes in operating working capital (excluding $(3)MM of M&S Inventory) and $(187)MM of working capital changes associated with investing activities3 Cash balance as of July 3rd; inclusive of AMT refund and excludes all other activity incurred post June 30th

See the 2Q20 Investor Packet at https://ir.marathonoil.com/ for non-GAAP reconciliations

817 774

522611

94 137

261

9 89

0

500

1,000

3/31/20 CashBalance

Operating CashFlow b/f WC

CapitalExpenditures

Cash Bal b/f A&Dand Working

Capital

WorkingCapital

A&D (net) 6/30/20 CashBalance

AMT Refund 7/3/20 CashBalance - Pro

forma

$m

illio

ns

1 2

3

6

https://ir.marathonoil.com/

Competitively Advantaged Multi-Basin Model

High quality U.S. assets span development cycle

Eagle Ford

2Q20 avg. 108 MBOED (61% oil)

~160,000 net acres

Bakken


~260,000 net acres

STACK / SCOOP


~300,000 net acres

7

Appraise / Delineate Early Development Full Field DevelopmentExplore

Northern Delaware


~85,000 net acres

Texas Delaware Oil Play>60,000 net acres

Louisiana Austin Chalk~200,000 net acres

0

10

20

30

40

50

0

20

40

60

80

100

120

2Q19 3Q19 4Q19 1Q20 2Q20

Production Gross Wells Net WI Wells

Eagle Ford Driving Capital Efficiency Improvement

Production Volumes and Wells to Sales

Resumed activity in 3Q20 with no loss in efficiency

• 2Q20 production averaged 108 net MBOED

with 20 gross operated wells to sales in April

• Planning to average 2 rigs and 1 frac crew

over 2H20

• Expecting ~25 wells to sales for rest of year,

weighted to 4Q20

• Realizing continued completed well cost

(CWC) reductions and efficiency gains

– 2Q20 CWC per lateral foot down more than 10%

from 2019 average

– Line of sight to driving average CWC below $700

per lateral foot

– 2Q20 completion stages per day improved ~15%

from 2019 average

• Deployed proprietary Field Service

Management (FSM) technology to drive base

production and expense improvements

8

Op

era

ted

Wells t

o S

ale

s

MB

OE

D

Completed Well Cost per Lateral Foot

CW

C p

er

Late

ral F

oo

t

$600

$900

2018 1H19 2H19 1H20 2H20e

0

5

10

15

20

25

30

35

0

20

40

60

80

100

120

2Q19 3Q19 4Q19 1Q20 2Q20


Bakken Delivering Execution Excellence

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

Record low cash costs during 2Q20


with 8 gross operated wells to sales; majority

of wells brought online in April

• 2Q20 oil production averaged 80 net MBOPD,

inclusive of ~4 MBOPD of curtailments

• Planning to average 2 rigs and 1 frac crew

over 2H20

• Expecting ~25 wells to sales over 2H20,

weighted to 4Q20

• Relentless focus on well costs and capital

efficiency

– New quarterly record for completion stages per

day

– 4 of 8 wells achieved average CWC below $500

per lateral foot; all 4 were in Myrmidon

– Line of sight to driving average CWC to ~$450

per lateral foot

9

MB

OE

D

Completed Well Cost per Lateral Foot

CW

C p

er

Late

ral F

oo

t

$400

$600

2018 1H19 2H19 1H20 2H20e

0

5

10

15

20

25

0

5

10

15

20

25

30

2Q19 3Q19 4Q19 1Q20 2Q20


0

4

8

12

16

20

0

20

40

60

80

100

2Q19 3Q19 4Q19 1Q20 2Q20


Capital Allocation Optionality in Oklahoma and N. Delaware

Oklahoma Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

Assets focused on base performance and expense management

Oklahoma


with no gross operated wells to sales

• Oil production averaged 15 net MBOPD,


• No wells to sales planned for rest of year

Northern Delaware


with 6 gross operated wells to sales

• Oil production averaged 16 MBOPD,


• Limited wells to sales over balance of year

10

MB

OE

D

N. Delaware Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

MB

OE

D

0

25

MRO RExWells

2019Industry

DelawareBasin

MRO RExWells

2019Industry

DelawareBasin

Encouraging Texas Delaware Oil Play Results2020 Resource Play Exploration (REx) D&C activity completed

• 4 Woodford wells and 2 Meramec wells

successfully brought online since play entry

• Wells demonstrate strong productivity, high

oil cuts, and shallow declines

– Gas-oil ratios in line with pre-drill expectations

– Low water-oil ratios of ~1:1

– No H2S and negligible CO2, as expected

• Productivity compares favorably against

industry Delaware Basin Wolfcamp and

Bone Spring wells; water-oil ratios also

lower

• Program has shown significant and

continuous improvement in drilling and

completion costs

11

1 90 day average includes 4 wells with >90 days of production and 180 day average includes 3 wells with >180 days of production

2 Source: Enverus production data for horizontal wells in Delaware DI Basin with 1st production date in 2019 and gross perforated interval over 1,000 feet

90-Day 180-Day

Av

era

ge C

um

ula

tiv

e

MB

OE

per

1,0

00’

Oil

Gas

1 1

2 2

Woodford Well

Meramec Well

Texas Delaware Oil Play Producing Wells

MRO Acreage

Marathon Oil vs. Industry Productivity

International E&P: Equatorial Guinea

• 2Q20 production of 83 net MBOED with unit

production costs of $1.88 per BOE

• Expecting sequentially lower 3Q20 production

due to impact of higher prices on net interest

under production sharing contract (PSC) as well

as natural decline

• Lower realized condensate pricing in 2Q20

reflected timing of liftings into oversupplied

market

• Third party Alen backfill gas project progressing

on schedule with startup expected in early 2021

Alen backfill gas project progressing on schedule

12

Alen Slug Catcher

Alen Pipeline Shore Landing

Committed to Sustainability

1 Methodology and definitions based on information from online 2018 MRO Sustainability Report

2 Based on Total Recordable Incident Rate 4 Metrics impact short-term incentive plan

3 World Health Organization

The foundation for long-term financial outperformance

Environmental & Safety1 Social Governance

• Leveraging the Bioko Island

Malaria Elimination Project

vaccine lab, endorsed by the

WHO3 to test more than 35,000

people in Equatorial Guinea for

COVID-19

• Working with community partners

to transition education programs

to distance learning

• Supporting local communities

through virtual volunteer

opportunities

• Protecting our business and

communities through our Business

Continuity and Emergency

Response Plans

• Year-to-date safety performance is

best in Company history2

• 96% total Company gas capture

during 2Q20 and year-to-date

• In 2019, achieved 19% reduction in

methane intensity relative to 2018

and 44% reduction relative to 2014

• In response to COVID-19,

Business Continuity and

Emergency Response Plan

continued with uninterrupted field

operations and work from home

practices

• 7 of 8 directors are independent

with lead independent director; 25%

of Board is female

• ~5 year average director tenure;

50% of directors joined in last 36

months

• All committees made up of entirely

NYSE independent directors

• GHG intensity metric added to

2020 executive compensation

scorecard4

• Base salary reductions for CEO and

other corporate officers and

reduction of Board of Director

compensation in 2020

13

Prioritizing Financial Strength and Flexibility

Reduction of $100MM

vs. prior guidance

2020 Capital Budget

Reduced

FCF breakeven in low $30/bbl range for 2H20

$1.2B

Significant

Liquidity

$3.5BNo significant maturities

until Nov. 2022

Reducing Capital

Expenditures

Managing Cost

Structure

Protecting Balance Sheet

and Liquidity

2020 Oil Production

Raised

190 MBOPDMidpoint of revised

guidance, inclusive of

curtailments

July 3rd Cash

Balance1

Pro-forma for Alternative

Minimum Tax refund

Record Low U.S.

Production Expense

$4.09/BOEDown ~20% from 2019

~17%

14

$611MM

Annualized G&A

Reduction

Relative to

2019

1 Inclusive of AMT refund and excludes all other activity incurred post June 30th

2 Delivers in-line oil production relative to expected 4Q20 total company average (>170 MBOPD) on an unhedged basis

See the 2Q20 Investor Packet at https://ir.marathonoil.com/ for non-GAAP reconciliations

2021 FCF Breakeven of ~$35/bbl for benchmark maintenance scenario2

https://ir.marathonoil.com/

Appendix

2020 Production Guidance

Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

2020 2Q20 1Q20 2019* 2020 2Q20 1Q20 2019*

United States 173 – 179 182 207 191 295 – 305 307 340 323

International 13 – 15 15 14 15 75 – 79 83 82 85

Total Net Production 186 – 194 197 221 206 370 – 384 390 422 408

* Divestiture-adjusted

16

• Revised midpoint of 2020 total Company oil production guidance 190 MBOPD

• Revised guidance inclusive of all curtailments; prior guidance was on an underlying basis and excluded the impact

of curtailments, which totaled ~11 MBOPD during 2Q20

2020 Cost and Tax Rate Guidance

Current

2020 Guidance

United States Cost Data ($ per BOE)

Production Operating $4.25 – 5.25

DD&A $19.00 – 21.00

S&H and Other1 $3.85 – 4.10

International Cost Data ($ per BOE)

Production Operating $2.15 – 2.65

DD&A $2.50 – 3.50

S&H and Other1 $0.10 – 0.60

Expected Tax Rates by Jurisdiction:

United States and Corporate Tax Rate –

Equatorial Guinea Tax Rate 25%

1 Excludes G&A expense

17

United States Crude Oil DerivativesAs of August 5, 2020

3Q20 4Q20 FY 2021

NYMEX WTI Three-Way Collars

Volume (Bbls/day) 80,000 80,000 -

Ceiling $64.40 $64.40 -

Floor $55.00 $55.00 -

Sold put $48.00 $48.00 -

NYMEX WTI Two-Way Collars

Volume (Bbls/day) 36,739 10,000 10,000

Ceiling $41.14 $48.65 $52.37

Floor $31.47 $37.00 $35.00

Fixed Price WTI Swaps

Volume (Bbls/day) 10,000 - -

Weighted Avg Price per Bbl $32.77 - -

Basis Swaps – Argus WTI Midland (a)

Volume (Bbls/day) 15,000 15,000 -

Weighted Avg Price per Bbl $(0.94) $(0.94) -

Basis Swaps – NYMEX WTI / ICE Brent (b)

Volume (Bbls/day) 5,000 5,000 808

Weighted Avg Price per Bbl $(7.24) $(7.24) $(7.24)

NYMEX Roll Basis Swaps

Volume (Bbls/day) 60,000 30,000 -

Weighted Avg Price per Bbl $(1.58) $(0.81) -

(a) The basis differential price is indexed against Argus WTI Midland

(b) The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI

18

United States Natural Gas/NGL DerivativesAs of August 5, 2020

(a) The basis differential price is indexed against Waha and NYMEX Henry Hub

19

3Q20 4Q20 FY 2021

Natural Gas

Two-Way Collars

Volume (MMBtu/day) 66,304 150,000 112,329

Weighted Avg Price per MMBtu

Ceiling $2.49 $2.62 $3.00

Floor $2.00 $2.13 $2.42

Basis Swaps – WAHA / HH (a)

Volume (MMBtu/day) 10,000 10,000 -

Weighted average price per MMBtu $(0.37) $(0.37) -

NGL

Fixed Price Ethane Swaps

Volume (Bbls/day) 7,304 10,000 -

Weighted average price per Bbl $8.78 $8.78 -

Capital, Investment & ExplorationBudget reconciliation ($MM)

2020

Budget

1Q20

Actual

2Q20

Actual

Cash additions to Property, Plant and Equipment 620 326

Working Capital associated with PPE (52) (187)

Property, Plant and Equipment additions 568 139

Exploration Costs other than Well Costs 6 8

M&S Inventory & Other 5 (10)

Total Capital Expenditure 1,200 579 137

20

• Updated capital budget of $1.2B compares to 1Q20 guidance of

Documents

SECOND QUARTER 2020...•2020 capex guidance reduced to $1.2 billion on strong execution and capital efficiency − 50% reduction vs. beginning of year capital budget − 2H20 spend