Financial and Operational Review

August 7, 2019

Second Quarter 2019

Forward-Looking Statements and Other Matters

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 2019 capital budget and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, 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, including CROIC and CFPDAS, and EG EBITDAX, asset sales and acquisitions, leasing and exploration activities, future financial position, tax rates and other plans and objectives for future operations. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “future”, “guidance,” “intend,” “may,” “outlook”, “plan,” “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, without limitation: conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the jurisdictions in which the Company operates, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; capital available for exploration and development; risks related to our hedging activities; well production timing; drilling and operating risks; 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; acts of war or terrorism, and the governmental or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company’s 2018 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.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 organic free cash flow and E.G. EBITDAX. Reconciliations of the differences between non-GAAP financial measures used in this presentation and their most directly comparable GAAP financial measures are available at www.Marathonoil.com in the 2Q19 Investor Packet.

2

Multi-Basin Portfolio• Capital allocation flexibility, broad market access, supplier diversification,

rapid sharing of best practices, platform for talent development

Balance Sheet Strength• Financial flexibility to execute business plan across broad range of

pricing; current net debt/EBITDAX among lowest in peer group

Differentiated Execution• Continuous improvement in capital efficiency and operating costs

while enhancing our resource base; delivering on our commitments

Framework for SuccessOur working definition of capital discipline

Powered by our Foundation

Committed to our Framework

Corporate Returns• Portfolio transformation and focused capital allocation drive multi-year

corporate returns improvement through capital efficient oil growth

Free Cash Flow • Sustainable free cash flow at conservative pricing

Return of Capital• Return incremental capital to shareholders in addition to peer

competitive dividend; funded through free cash flow, not dispositions

3

2Q19 HighlightsConsistently delivering on our framework

4

• Annualized 2Q19 CROIC1 of 20%, comparable to prior-year quarter despite 12% lower

WTI price; driving significant price normalized rate of change improvement

• Organic FCF2, post-dividend, of $137MM 2Q19 and $217MM YTD

• YTD dividends of $82MM, buybacks of $250MM; 25% of CFO3 returned to shareholders

• Share repurchases of $950MM since 2018, funded entirely by organic FCF

• Share repurchase authorization increased to $1.5B

• US oil production above top end of guidance and up 17% from year-ago quarter

• YTD development capex 50% of annual budget; annual $2.4B budget unchanged

• US unit production costs down 14% from year-ago quarter; lowest since becoming

independent E&P

• Completed well cost (CWC) per lateral foot on declining trend vs. 2018 in all Basins

• Exited Kurdistan and U.K.; 10 country exits since 2013

• Portfolio optimized to four high quality U.S. Resource Plays and free cash flow

generative integrated business in Equatorial Guinea

• Upgraded by Moody’s and S&P; investment grade at all primary ratings agencies

• Peer leading leverage metrics and breakeven oil price

Corporate Returns

Free Cash Flow

Return of Capital

Multi-Basin

Portfolio

Balance Sheet

Strength

Differentiated

Execution

1CROIC = Cash return on invested capital; calculated by taking cash flow (Operating Cash Flow before working capital + net interest after tax) divided

by (average Stockholder’s Equity + average Net Debt)2Organic FCF = Operating Cash Flow before working capital (excl. exploration costs other than well costs), less Development Capex, less Dividends,

plus EG return of capital & other 3CFO = Cash flow from operations

Total Company Cash Flow for 2Q19

• 2Q19 development capital of $636MM; YTD of $1.2B with $2.4B full-year budget unchanged

• YTD stock repurchases of $250MM; outstanding authorization raised to $1.5B

• Cash Balance at June 30 excludes $335MM of held for sale cash (U.K.); pro-forma July 1 Cash

Balance reflects $95MM U.K. disposition proceeds

Generated $137MM of organic FCF

5

1,0191,156

9611,056

777 636

41

37

37 236 4

74

0

500

1,000

1,500

2,000

3/31/19 CashBalance

OperatingCash Flow b/f

WC

DevelopmentCapital

Expenditures

Dividends EG LNGReturn ofCapital &

Other

Cash Bal b/fA&D, REx,WorkingCapital &Financing

REx Capex ShareRepurchase

A&D (Net) TotalWorkingCapital

6/30/19 CashBalance

7/1/19 pro-forma Cash

Balance

$M

M

1 2

U.K. Held

for Sale

1 Excludes $6MM of exploration costs other than well costs2 Total working capital includes $20MM and $54MM of working capital changes associated with operating activities and investing activities, respectively

See the 2Q19 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations

Appraise / Delineate Early Development Full Field Development

Competitively Advantaged Multi-Basin Model

Multi-basin portfolio provides flexibility

Eagle Ford

2Q19 avg. 109 MBOED (56% oil)

~145,000 net surface acres

Northern Delaware

2Q19 avg. 28 MBOED (59% oil)

~85,000 net surface acres

Bakken

2Q19 avg. 104 MBOED (85% oil)

~260,000 net surface acres

STACK / SCOOP

2Q19 avg. 82 MBOED (25% oil)

~300,000 net surface acres

MRO 2Q19 Oil Production by Area

Eagle Ford

Bakken

Permian

Oklahoma

International and Other

6

Impressive Eagle Ford Productivity Across Footprint

Driving Consistent Productivity Improvement

Production Volumes and Wells to Sales

0

20

40

60

0

40

80

120

2Q18 3Q18 4Q18 1Q19 2Q19

Op

era

ted

We

lls

to

Sa

les

Production Gross Wells Net WI Wells

MB

OE

D

• Production averaged 109 net MBOED

• Record 2Q19 IP30 well productivity despite majority of activity outside of Karnes County

• Turnbull pad in Karnes avg. IP30 of 3,230 BOED (67% oil) - new MRO pad record

• 15 wells across Atascosa Core delivered avg. IP30 of 1,860 BOED (81% oil)

• Successful core extension test in Gonzales through enhanced completion designs

− 6 well pad achieved avg. IP30 of 1,600 BOED (70% oil)

− 2nd Gonzales test online 4Q19

• Capital efficiency improvement continues

− Consistent year over year productivity improvement

− Completed well cost per lateral foot on declining trend vs. 2018

90-D

ay C

um

Pro

du

cti

on

(M

BO

E)1

7

0

20

40

60

80

100

120

2011 2012 2013 2014 2015 2016 2017 2018 2019

1 90-day cumulative production normalized to 5,700’

Record Well Performance in the Eagle Ford

IPs shown are 30-day (includes oil, NGL and gas) and represent pad average

8

Live Oak

Bee

Karnes

Atascosa

Gonzales

De Witt

Wet Gas

Condensate

Oil

Successful Gonzales core extension test

Expanded Atascosa Core

Turnbull H – 4 LEF wells

3,230 BOED (67% oil)

6,140’ LL

Retzloff Tom-May - 3 LEF wells

1,660 BOED (80% oil)

6,830’ LL

Chapman-Pfeil - 4 LEF wells

1,320 BOED (76% oil)

6,760’ LL

MRO Eagle Ford Record

Pad IP30

Barnhart G - 6 LEF wells

1,600 BOED (70% oil)

5,680’ LL

Core Extension Test in

Gonzales

Next Gonzales Test (4Q19)

4 LEF Wells

9,600’ LL

Guajillo – 2 pads, 8 LEF wells

2,200 BOED (83% oil)

6,820’ LL

• Production averaged 104 net MBOED

• Continuing successful Southern Hector delineation

− 4 second quarter wells avg. IP30 of 2,450 BOED (80% oil)

• Strong performance from South Myrmidon

− 15 wells avg. IP30 of 2,820 BOED (80% oil)

− Driftwood Middle Bakken well achieved MRO record IP24 of 12,250 BOED (78% oil)

• Average completed well cost of $5.2MM

• YTD CWC down 15% from 2018 average

• Half of second quarter wells at or below $5MM

• Exceptional extended production from 2018 core extension tests in Ajax and Southern Hector

YTD Completed Well Costs Trending 15% below 2018

Industry Leading Capital Efficiency in Bakken

0

5

10

15

20

25

30

35

0

20

40

60

80

100

120

2Q18 3Q18 4Q18 1Q19 2Q19

Production Gross Wells Net WI Wells

MB

OE

D

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

9

4.0

5.0

6.0

7.0

8.0

1Q18 2Q18 3Q18 4Q18 1Q19 2Q19

CW

C (

$M

M)

McKenzie

Dunn

Myrmidon

Hector

Ajax

Elk Creek

2Q19 to Sales

Pre-2Q19 to Sales

Expanding the Bakken CoreBest in Basin productivity

10

IPs shown include oil, NGL and gas

1Source - Drilling Info; dataset consists of all Bakken/Three Forks wells with first production from since Jan. 1, 2017. Plot includes 1,564 total wells.

*CUM – Cumulative production

1

• 4 wells from Ajax core extension test achieved total cumulative production of >1 MMBOE at 240 days

• 4 wells from South Hector core extension tests achieved total cumulative production of >950 MBOE at 200 days

• Additional Southern Hector and Ajax core extension tests scheduled for 2H19

Extended Production Validates

2018 Delineation Tests

4 Ajax wells (4Q18)

>1 MMBOE (80% oil)

Total CUM* at 240 days

4 S. Hector wells (2H18)

>950 MBOE (79% oil)

Total CUM* at 200 days

Progressing Southern

Hector Delineation

4 wells (2Q19)

IP30: 2,450 BOED (80% oil)

Continued Strength in

South Myrmidon

15 wells (2Q19)

IP30: 2,820 BOED (80% oil)

Includes single well IP24

12,250 BOED (78% oil)

90-Day Cumulative Oil Production1

0

40

80

120

160

200

240

Cu

mu

lati

ve O

il (

MB

O)

20 of top 25 & 60 of top 100

wells, despite only drilling

9% of wells in Basin

MRO Wells Competitor Wells

0 500 1,000 1,500

$8.0

$6.3$5.9

~$0.5

~$0.5

~$0.5

~$0.2

~$0.4

5

5.5

6

6.5

7

7.5

8

Prior ActualCWC**

DrillingEfficiencies

ContractSavings

CompletionEfficiencies

DesignSavings

Actual CWC Location Actual D&C

0

4

8

12

16

20

0

20

40

60

80

100

2Q18 3Q18 4Q18 1Q19 2Q19

Production Gross Wells Net WI Wells

Oklahoma Delivering Capital Efficiency and Consistency

• Production averaged 82 net MBOED

• Track record of consistently strong

overpressured STACK infill results

– 8 wps Mike Stroud infill >100% above type

curve at 60 days

• Focus on capital efficiency paying dividends

– Most recent overpressured STACK infills

(Marjorie and Lloyd) executed at industry

leading well costs

– Cycle times reduced ~30% vs. most recent

comparable infills

• Leveraging operated success and OBO

learnings to Springer formation over 2H19

– 4Q18 Papa Pump Springer test achieved

IP180 of 1,210 BOED (79% oil)

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

MB

OE

D

11

Marjorie/Lloyd Overpressured STACK Well Cost*

Co

mp

lete

d W

ell C

ost

($M

M)

*Normalized to 10,000 ft. lateral; completed well cost includes D&C and location costs. Actual D&C is CWC minus location costs

**Actual average CWC of two most recent offset infills

wps – wells per section

OBO – operated by other

Oklahoma Continues to Outperform

IPs shown are 30-day (includes oil, NGL and gas) and represent pad average unless otherwise stated

*normalized to 10,000 ft. lateral

**5 of 8 wells brought online during 1Q19; 3 of 8 wells brought online during 2Q19

MRMC – Meramec

Leveraging operated Springer success in 2H19

12

Caddo

Grady

Stephens

Blaine

Canadian

Kingfisher

Wet Gas

Condensate

Oil

2Q19 to Sales

2H19 to Sales

Pre-2Q19 to Sales

0

50

100

150

0 10 20 30 40 50 60

MRMC Volatile Oil XL Type Curve

Mike Stroud Pad Avg

Chapman Pad Avg

Strong Performance from the Overpressured STACK

Days

MB

OE

>100%

Industry Leading

Well Costs

Marjorie & Lloyd Infills

2 pads, 4 wps

6 new MRMC wells

$6.3MM avg. CWC*

Flowing back

Strong Productivity

and Predictability

Mike Stroud**

8 MRMC wps

2,480 BOED (38% oil)

Chapman

6 MRMC wps

1,810 BOED (53% oil)Leveraging Learnings

in Springer

2H19 - 12 wells to sales

4Q18 Springer Test

Papa Pump

IP180: 1,210 BOED

(79% oil)

Dual-Pad Development Reducing Costs and Cycle Times

• Production averaged 28 net MBOED

• Continued strong Upper Wolfcampproductivity in Malaga

– 11 wells avg. IP30 of 1,520 BOED (63% oil), or 345 BOED per one thousand foot lateral

• Improving margin profile through cost reductions and midstream solutions

– 10% sequential reduction in cash costs

– 100% water on pipe for 2Q19 and all remaining 2019 wells to sales

– Oil on pipe at ~70% and rising

• Increasing proportion of Red Hills delineation in drilling mix over 2H19

Strong Productivity and Improving Margins in N. Delaware

0

5

10

15

20

25

0

5

10

15

20

25

30

2Q18 3Q18 4Q18 1Q19 2Q19

Production Gross Wells Net WI Wells

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

MB

OE

D

0%

20%

40%

60%

80%

2Q18 3Q18 4Q18 1Q19 2Q19

% Water on Pipe

Water on Pipe (% of total produced)

13

Strong 2Q19 Upper Wolfcamp Performance in MalagaGreater proportion of 2H19 activity in Red Hills

IPs shown are 30-day (includes oil, NGL and gas) and represent pad average

Upper WC – Upper Wolfcamp horizon

BS – Bone Springs horizon14

Ranger

Red Hills

Malaga

Arrowhead

China

Draw

Eddy

Lea

Strong Upper WC

Productivity

Mariner, 6 Upper WC

1,350 BOED (64% oil)

305 BOED/1000’

Trebuchet, 3 Upper WC

1,580 BOED (64% oil)

370 BOED/1000’

Whistle Pig, 3 Upper WC/BS

1,870 BOED (64% oil)

420 BOED/1000’

2H19 Red Hills Pads

International Simplified to FCF Generating E.G. Business

• Total International production of 103 net

MBOED, reflecting successful return from

1Q19 E.G. turnaround

• E.G. EBITDAX1 of $142MM 2Q19 and

$211MM YTD

• International portfolio simplified to free cash

flow generating integrated business in E.G.

– Closed on sale of Atrush Block in Kurdistan

– Closed on U.K. divestiture July 1, removing

$966MM of asset retirement obligations

– 10 country exits since 2013

• Pro-forma International unit production

costs (ex Kurdistan and U.K.) just $2.21 per

BOE during 2Q19; guidance updated

15

Alba Platform

AMPCO Methanol Plant

EGLNG Loading Dock

1See the 2Q19 Investor Packet at www.Marathonoil.com for Non-GAAP reconciliations

Well Established Track Record of FCF & Return of Capital

16

• Returned ~$1.2B of capital to shareholders since 2018, representing ~25% of operating

cash flow, funded entirely by organic FCF

• Buyback authorization raised to $1.5B, representing $950MM increase in authorization

• Return of capital included in executive compensation scorecard

• Underlying free cash flow momentum accelerating into 2H19 and 2020

$M

M

4%

5%

6%

7%

8%

9%

10%

11%

12%

0

500

1,000

1,500

2018 2019 YTD Since 2018

Organic FCF before Dividend Repurchases FCF Yield Dividend

An

nu

alized

FC

F

Yie

ld (

%)

251

950

82

250

169

1,037

299

1,336

700

Avg WTI Price: $64.90 $57.42 $62.42

FCF YieldDividendRepurchasesOrganic FCF before Dividend

FCF Yield = Organic FCF before Dividend / Market Cap (as of 8/5/2019)

Six consecutive quarters of organic FCF generation

Appendix

Portfolio Transformation Since 201310 Country Exits

18

CORE ASSETS

DIVESTED

CANADA

(2017)

BAKKEN

SCOOP/STACK

EAGLE FORD

NORTHERN

DELAWARE

EQUATORIAL

GUINEA

GABON

(2018)

ANGOLA

(2014)

KURDISTAN (2019)

LIBYA (2018)

NORWAY

(2014)

UNITED KINGDOM

(2019)

POLAND

(2014)

ETHIOPIA (2016)

KENYA

(2016)

• Optimized portfolio positioned to sustainably deliver improving corporate returns, free cash flow, and

return of capital

• Simplification to core assets concentrates capital allocation to highest margin, highest return US

resource plays while materially reducing cash costs

• Portfolio simplification has contributed to an Asset Retirement Obligation reduction of $1.8B since 2014

Differentiated Execution Led the Way in 2018Underpins confidence in ongoing delivery on our framework for success

2018 ObjectivesInitial Guidance Actual Delivery

@$50/bbl WTI @$65/bbl WTI

Capital Discipline $2.3B development capital $2.3B development capital

Corporate Returns30% CROIC improvement

78% CROIC improvement –

best in proxy peer group*

10% CFPDAS improvement 65% CFPDAS improvement

Free Cash FlowOrganic FCF positive, post-

dividend, above $50/bbl WTI

$865MM of post-dividend,

organic FCF

Return of CapitalPrioritize incremental return,

above dividend, through

sustainable organic FCF

$700MM of share buybacks

and $170MM dividend

Capital Efficient Oil

Growth

18% total oil growth at

midpoint, divestiture

adjusted

24% total oil growth,

divestiture adjusted –

best in proxy peer group*

22.5% resource play oil

growth at midpoint

32% resource play oil

growth

* Proxy peer group includes – APA, APC, CHK, CLR, DVN, ECA, EOG, HES, MUR, NBL, PXD

19

2019 Production Guidance

3Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

3Q19 2Q19* 3Q18* 3Q19 2Q19* 3Q18*

United States 190 – 200 192 172 330 – 340 331 302

International 12 – 16 16 17 80 – 90 91 99

Total Net Production 202 – 216 208 189 410 – 430 422 401

* Divestiture-adjusted, and also removes volumes associated with the sale of our U.K. business which closed on July 1, 2019

** Annual 2019 guidance includes 1H19 contributions from divested assets

FY19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

2019** 2018* 2019** 2018*

United States 185 – 195 169 320 – 330 294

International 18 – 22 17 85 – 95 98

Total Net Production 203 – 217 186 405 – 425 392

20

• Adjusted full year 2019 production guidance now excludes divested U.K. and Kurdistan volumes for

the second half of 2019, but otherwise remains unchanged

2019 Cost and Tax Rate Guidance

Initial

2019 Guidance

Current

2019 Guidance

United States Cost Data ($ per BOE)

Production Operating $4.50 – 5.50 $4.50 – 5.50

DD&A $19.25 – 21.75 $18.25 – 20.75

S&H and Other1 $4.00 – 4.50 $4.00 – 4.50

International Cost Data ($ per BOE)

Production Operating $4.75 – 5.75 $3.75 – 4.25

DD&A $3.00 – 4.00 $3.00 – 4.00

S&H and Other1 $1.00 – 1.50 $0.75 – 1.25

Expected Tax Rates by Jurisdiction:

United States and Corporate Tax Rate –% –%

Equatorial Guinea Tax Rate 25% 25%

1 Excludes G&A expense

21

• Updated full year 2019 guidance reflects actual realized costs for 1H19 but excludes U.K. and

Kurdistan costs for 2H19

• 2Q19 pro-forma (ex U.K. and Kurdistan) International cost data ($ per BOE):- Production Operating $2.21

- DD&A $3.13

- S&H and Other $0.64

United States Crude Oil DerivativesAs of August 5, 2019

Crude Oil

3Q19 4Q19 FY 2020 FY 2021

NYMEX WTI Three-Way Collars (a)

Volume (BBLs/day) 80,000 80,000 19,945 -

Weighted Avg Price per BBL:

Ceiling $74.19 $74.19 $67.55 -

Floor $56.75 $56.75 $55.00 -

Sold put $49.50 $49.50 $47.50 -

Basis Swaps – Argus WTI Midland (b)

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

Weighted Avg Price per BBL $(1.40) $(1.40) $(0.94) -

Basis Swaps – Net Energy Clearbrook (c)

Volume (BBLs/day) 1,000 1,000 - -

Weighted Avg Price per BBL $(3.50) $(3.50) - -

Basis Swaps – NYMEX WTI / ICE Brent (d)

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

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

Basis Swaps – Argus WTI Houston (e)

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

Weighted Avg Price per BBL $5.51 $5.51 - -

NYMEX Roll Basis Swaps

Volume (BBLs/day) 60,000 60,000 - -

Weighted Avg Price per BBL $0.38 $0.38 - -

(a) Between July 1, 2019 and August 5, 2019, we entered into 10,000 Bbls/day of three-way collars for January – December 2020, with a ceiling of $65.12, a sold put of $48.00, and

a floor of $55.00.

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

(c) The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook (“UHC”)

(d) The basis differential price is indexed against International Commodity Exchange (“ICE”) Brent and NYMEX WTI

(e) The basis differential price is indexed against Argus WTI Houston

22

2019 Capital, Investment & ExplorationBudget reconciliation $MM

Development Capital 2019

Budget 1Q19 2Q19

2019 YTD

Actual

Cash additions to Property, Plant and Equipment 615 647 1,262

Working Capital associated with PPE (1) 54 53

Property, Plant and Equipment additions 614 701 1,315

M&S Inventory (4) (6) (10)

REx expenditures included in capital expenditures (41) (59) (100)

Exploration costs other than well costs - - -

Development Capital 2,400 569 636 1,205

23

Resource Exploration (REx) Capital 2019

Budget 1Q19 2Q19

2019 YTD

Actual

REx expenditures included in capital expenditures 41 59 100

Additions to Other Assets and acquisitions (14) (28) (42)

Exploration costs other than well costs 10 6 16

REx Capital Expenditure 200 37 37 74