Financial and Operational Review

November 6, 2019

Third 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 E.G. 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”, “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, 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; our ability to complete our announced acquisitions on the timeline currently anticipated, if at all; well product ion 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 or initiatives, including initiatives addressing the impact of global climate change, flaring or water disposal; 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 3Q19 Investor Packet.

2

Framework for SuccessOur working definition of capital discipline

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

Differentiated Execution• Continuous improvement in capital efficiency and operating costs

while enhancing our resource base; delivering on our commitments

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

Consistently Delivering on our Framework

• YTD annualized CROIC1 of 20%, comparable to 2018 average despite 12% lower WTI

price; driving significant price normalized rate of change improvementCorporate Returns

• Organic FCF2, post-dividend, of $81MM 3Q19 and $298MM YTDFree Cash Flow

• YTD dividends of $122MM and share repurchases to date of $300MM

• Cumulative return of capital of ~$1.3B since 2018, including ~$1B of share repurchases,

funded entirely by organic FCF

• 25% of CFO3 returned to shareholders and share count reduced by 7% since 2018

Return of Capital

• Closed on U.K. sale; 10 country exits since 2013

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

integrated business in Equatorial Guinea (E.G.)

Multi-Basin

Portfolio

• Executed 3 separate financing transactions that are collectively leverage neutral, extend

maturities, and generate cash savings

• Investment grade at all primary ratings agencies; conservative leverage metrics and low

breakeven oil price

Balance Sheet

Strength

• Full year U.S. oil production growth guidance increased to 13% from 12% previously; 3Q

U.S. oil production above top end of guidance and up 17% from year-ago quarter

• YTD development capex in-line with expectations and annual $2.4B budget unchanged

• Unit production costs at record low since becoming independent E&P

• Success across all elements of returns focused resource capture and enhancement

framework; added over 1,000 operated locations or ~3 years of drilling inventory

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

Strong financial outcomes support return of cash to shareholders

4

5

Organic Enhancement>500 locations added

• Adding Inventory & Upgrading Quality: Eagle Ford and Bakken have added

over 500 locations since beginning of 2018, while also upgrading hundreds of

locations to top tier returns

• Extending Runway: Vast majority of future Bakken and Eagle Ford inventory

offers top tier returns, enhancing capital allocation optionality

• Thinking Next Generation: Second phase of Eagle Ford EOR progressing with

encouraging early results

Resource Play Exploration

>400 potential locations

• Advancing exploration and appraisal in two oil plays of scale

• New Texas Delaware Oil Play: Contiguous, oily, 60,000+ net acreage position at

low entry cost; early wells demonstrate strong oil productivity and low water cut;

potential for over 400 extended lateral locations

• Louisiana Austin Chalk: Progressing exploration activities in capital

disciplined manner through partnership with EQNR; initial results early next year

Bolt-on Acquisitions & Trades

>150 locations*

• Eagle Ford Bolt-on: ~18,000 contiguous, largely undeveloped net acres

adjacent to existing MRO leasehold; meaningful midstream synergies and proven

well results; cores up high return 70 location development area with upside

potential

• Trades: Captured >100 locations this year, largely in Northern Delaware

Success Across All Elements of Resource Enhancement Framework

Over 1,000 locations added, equivalent to ~3 years of drilling inventory

>1,000 locations (~3 years of inventory) added

All locations referenced are gross company operated

*Includes locations associated with Eagle Ford bolt-on expected to close before January 31, 2020

Organic Enhancement in Bakken & Eagle FordAdding economic inventory and upgrading inventory quality

0

25

50

75

100

Pre-EnhancedCompletions

2019

0

2

4

6

8

Pre-EnhancedCompletions

2019

>2x -30%

Bakken Hector Area: Transformative

Productivity Uplift and Cost Reductions

CW

C (

$M

M)

6

Pre-2018 Eagle Ford Current Eagle Ford

Live Oak

Karnes

Atascosa

Gonzales

De Witt

Live Oak

Karnes

Atascosa

Gonzales

De Witt

Top Tier Enhancement Potential

Avg

. 6

0-d

ay

CU

M O

il

(MB

O)

Eagle Ford Oil Productivity up ~75% since

2015; Atascosa on Par with Core Karnes

Avg

. 6

0-d

ay

CU

M O

il

(MB

O)

0

10

20

30

40

50

60

70

2015 2016 2017 2018 2019

Karnes Atascosa

* **

*Average 60-day MRO Bakken/Three Forks well performance from 2015 and 2016

**Average CWC for all MRO Bakken/Three Forks wells in 2017

***2019 YTD development wells in Hector area

McKenzie

Dunn

Myrmidon

Hector

Ajax

Elk Creek

McKenzie

Dunn

Myrmidon

Hector

Ajax

Elk Creek

Pre-2018 Bakken Current Bakken

Top Tier Enhancement Potential

*** ***

OSAGE

DELAWARE

BASINMIDLAND

BASIN

Woodford Depth

MRO Leases*

• Contiguous, oily, 60,000+ net acreage position in Texas Delaware at low entry cost of less than $2,400 per acre

• Prospective for both Woodford and Meramec

− Woodford over 350 feet thick

− 700 feet of separation between Woodford and Meramec landing zones

− Two excellent source rocks: Woodford and Barnett

• Initial two wells demonstrating impressive productivity, low water/oil ratios, shallow decline profiles

• Encouraging results support full rig-line for appraisal and delineation in 2020

New Texas Delaware Oil PlayPotential for over 400 extended lateral locations

7

GR

0-200

RESD

0.2-2000

GR

0-200

RESD

0.2-2000

Play Stratigraphy

WDFD – Woodford

*Includes acquired leases expected to close during 4Q19

Oklahoma SCOOP Grady Co.

Texas DelawareWinkler Co. MRO Acreage

Landing Zones

Louisiana Austin ChalkExploration drilling ongoing and acquiring 3D seismic

8

• Progressing exploration in capital disciplined manner with EQNR as new 25% non-operating, working interest partner

• MRO acreage focused in Western Fairway

− Overpressured volatile oil and condensate phase windows with higher porosity

− Undrilled acreage position offsetting historic Austin Chalk wells with prolific cumulative oil production

• Results from first exploration well expected early 2020; second exploration well to spud before end 2019

Brownstone Shale Pressure SealUpper Austin Chalk

Lower Austin Chalk Reservoir

Eagle Ford Shale

High Pressure – High Porosity Lower Pressure – Lower Porosity

Upper Cretaceous Chalk

WESTERN FAIRWAY EASTERN FAIRWAY

MRO well

Results 1H20

MRO well

(spud 12/2019)Wet Gas

Volatile Oil &Condensate

Black Oil

Historical Austin Chalk

Wells with >500 MBO

Recent Industry Wells

MRO Leases

Adding Quality and Scale to Northeast Eagle Ford Enhancing resource base through synergistic, targeted bolt-on

9

• ~18,000 contiguous, largely undeveloped net acres adjacent to existing MRO Northeast Eagle Ford leasehold

− Current production of ~7,000 BOED (36% oil; 67% liquids)

− Attractive midstream infrastructure (gas lines, central facilities, freshwater wells)

• Midstream assets synergistic with legacy MRO position

• Cores up ~70 well (>8k foot laterals), high return development area with upside potential

• Acquired acreage responding well to modern completion designs

• Effective date of November 1, 2019 with expected close by January 31, 2020

Synergistic Bolt-on to MRO Shiner Development Area

GonzalesMRO Acreage

Acquisition Acreage

De Witt

Karnes

Wilson

Atascosa

Shiner

(MRO)

Water Facility

Central

Facility

Lavaca

Well B*

2,550 BOED

(59% oil)

IP30

Well A*

1,880 BOED

(52% oil)

IP180

~70 Well Development Area

MRO Acreage

Acquisition Acreage

Water Facility

Central Facility

Midstream Infrastructure

Wells

*Wells on acquired acreage were drilled and completed by acquisition counterparty

Competitively Advantaged Multi-Basin Model

Multi-basin portfolio provides flexibility; assets span the development cycle

Eagle Ford

3Q19 avg. 107 MBOED (59% oil)

~160,000 net acres**

Bakken

3Q19 avg. 109 MBOED (84% oil)

~260,000 net acres

STACK / SCOOP

3Q19 avg. 84 MBOED (27% oil)

~300,000 net acres

10

Appraise / Delineate Early Development Full Field DevelopmentExplore

Northern Delaware

3Q19 avg. 30 MBOED (60% oil)

~85,000 net acres

New Texas Delaware Oil Play

>60,000 net acres*

Louisiana Austin Chalk

~200,000 net acres

* Includes acquired leases expected to close during 4Q19

**Includes acreage associated with Eagle Ford bolt-on expected to close before January 31, 2020

Strong Results Continue Across Eagle Ford Footprint

Driving Consistent Productivity Improvement

Production Volumes and Wells to Sales

0

20

40

60

0

40

80

120

3Q18 4Q18 1Q19 2Q19 3Q19

Op

era

ted

We

lls

to

Sa

les

Production Gross Wells Net WI Wells

MB

OE

D

Record IP30 oil productivity for the quarter

• Production averaged 107 net MBOED

• Record IP30 oil productivity during 3Q, up over 25% vs 2018 average

• Strong results across Core Karnes and expanded Atascosa Core

− 5 Austin Chalk wells in Karnes achieved avg. IP30 of 2,550 BOED (78% oil)

− 9 wells in Atascosa delivered avg. IP30 of 1,780 BOED (87% oil)

• 10,900’ laterals at Middle McCowen highlight optionality for capital efficient, long lateral development in Atascosa

• Organically adding and upgrading inventory

• Karnes redevelopment test delivering top tier returns; 4 well pad avg. IP30 of 2,100 BOED (73% oil)

• 3Q CWC per lateral foot down ~10% vs 2018 90

-Da

y C

um

Pro

du

cti

on

(M

BO

E)

11

0

50

100

150

2011 2012 2013 2014 2015 2016 2017 2018 2019

CWC – Completed well cost

Extending the Eagle Ford Core and Enhancing Inventory

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

AC – Austin Chalk

LEF – Lower Eagle Ford12

Live Oak

Bee

KarnesAtascosa

Gonzales

De Witt

Wet Gas

Condensate

Oil

Successful redevelopment test in Core Karnes

Adams Tipton - 4 LEF wells

Infilling wider spaced, early generation

parent wells

2,100 BOED (73% oil)

6,250’ LL

Successful Redevelopment

Test in Core Karnes

4 LEF Wells (4Q19)

9,600’ LL

Middle McCowen – 4 LEF wells

1,745 BOED (88% oil)

10,900’ LL

2 pads, 5 AC wells

2,550 BOED (78% oil)

6,880’ LL

Impressive Austin Chalk

Performance

Maximizing Value through

Extended Laterals in Atascosa

74 Ranch Guajillo B - 5 LEF wells

1,800 BOED (85% oil)

5,610’ LL

Continued Success from the

Atascosa Core

Long Lateral Test in

Extended Gonzales Core

$7.5

$4.9

3.0

4.0

5.0

6.0

7.0

8.0

1Q18CWC

CompletionEfficiencies

DrillingEfficiencies

DesignSavings

ContractSavings

3Q19CWC

• Production averaged 109 net MBOED

• Impressive capital efficiency, highlighted by $4.9MM average 3Q completed well cost -down 20% from 2018

• Sustainable well cost reductions driven by efficiency gains and targeted design savings

− Achieved new single well drilling record -spud to total depth of less than 7 days

− Established new pad record for completion efficiency - 11 stages/day

− Average 3Q stages/day up 35% vs. 2018

• Extending the core - positive early results from latest South Hector delineation test

− 4 well Herbert pad achieved avg. IP30 of 1,720 BOED (86% oil) with average CWC of $4.5M

>35% Reduction in Well Costs from 1Q18 to 3Q19

Efficiency Gains Continue in Bakken

0

5

10

15

20

25

30

35

0

20

40

60

80

100

120

3Q18 4Q18 1Q19 2Q19 3Q19

Production Gross Wells Net WI Wells

MB

OE

D

Production Volumes and Wells to Sales

Op

era

ted

We

lls to

Sa

les

Record low completed well costs of less than $5MM

13

CW

C (

$M

M)

0

10

20

30

40

50

60

MRO Peer1

Peer2

Peer3

Peer4

Peer5

Peer6

Peer7

Peer8

McKenzie

Dunn

Myrmidon

Hector

Ajax

Elk Creek

Extending the Bakken CoreBest in basin productivity and superior economics

14

IPs shown include oil, NGL and gas

*Source - Drilling Info; dataset consists of the top 100 Bakken/Three Forks wells with first production since Jan. 1, 2017. Peers include: Bruin, CLR, COP, EOG, HES, OAS,

QEP, WPX

CUM – Cumulative production

Continued Success in

Southern Hector

Herbert Pad

4 wells

1,720 BOED (86% oil)

IP30

$4.5MM CWC

2018 Delineation Tests Paid Out in ~10 months

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

Top 100 Wells in the Williston Basin by 90-day

Cumulative Oil Production*

We

ll C

ou

nt

3Q19 to Sales

Pre-3Q19 to Sales

3.0

4.0

5.0

6.0

7.0

8.0

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

CW

C (

$) Herbert Pad CWC

of $4.5MM

Improving Capital Efficiency and Returns Through

Well Cost Reductions

60 of top 100 wells, despite only

drilling 9% of Wells in Basin

0

50

100

150

0 30 60 90

0

4

8

12

16

20

0

20

40

60

80

100

3Q18 4Q18 1Q19 2Q19 3Q19

Production Gross Wells Net WI Wells

Oklahoma Delivering Strong Results from Concentrated Oil Program

Production Volumes and Wells to Sales

Op

era

ted

We

lls to

Sa

les

MB

OE

D

Rig count reduced from 7 to 4

15

Marjorie/Lloyd Exceeds 10,000’ Expectations

MB

OE

Marjorie (3 Wells) ~7,500’ laterals

MRMC VO 10,000’

Lateral Type Curve

Lloyd (3 Wells) ~7,500’ laterals

• Production averaged 84 net MBOED

• Reducing and concentrating activity in higher return, more oily areas

• Consistently strong results from the overpressured STACK

– Marjorie & Lloyd infills (~7,500 ft. laterals) outperforming 10,000 ft. type curve by over 30% at 90 days

– Peer leading well costs of $6.3MM, normalized to 10,000 foot lateral

• Impressive early results from the SCOOP Springer

– 3 wells achieved IP30 rate of 1,460 BOED (72% oil), or 325 BOED per one thousand foot lateral

– 9 Springer wells to sales in 4Q19

Days

MRMC – Meramec

VO – Volatile oil

Improving Oklahoma Capital Efficiency

IPs shown are 30-day (includes oil, NGL and gas) and represent average for all wells referenced

*normalized to 10,000 ft. lateral

wps – wells per section

Early Springer results exceeding expectations

16

Caddo

Grady

Stephens

Blaine

Canadian

Kingfisher

Wet Gas

Condensate

Oil

4Q19 to Sales

3Q19 to Sales

Peer Leading Well

Costs

Marjorie & Lloyd Infills

2 pads, 4 wps

6 MRMC wells

$6.3MM avg. CWC*

1,740 BOED (66% oil)

Strong Results in Oil

Rich Springer

4Q19 - 9 wells to sales

Smith/Newby

3 Springer wells

1,460 BOED (72% oil)

325 BOED/1,000’

• Production averaged 30 net MBOED

• Continued strong Malaga Upper Wolfcamp productivity and capital efficiency

– 4 well Rick Deckard pad avg. IP30 of 1,810 BOED (63% oil), or 395 BOED per one thousand foot lateral

– 3Q productivity (IP30) per lateral foot up over 35% vs. 2018

– 3Q completed well cost per lateral foot down 20% vs. 2018

• Improving margin profile through cost reductions and midstream solutions

– 100% water on pipe for all remaining 2019 wells to sales; 70% oil on pipe

– Unit production costs continue trend lower

Driving Capital Efficiency Improvement in N. Delaware

0

5

10

15

20

25

0

5

10

15

20

25

30

3Q18 4Q18 1Q19 2Q19 3Q19

Production Gross Wells Net WI Wells

Production Volumes and Wells to Sales

Op

era

ted

We

lls to

Sa

les

MB

OE

D

17

Malaga Capital Efficiency Improvement

0

150

300

450

2018 2019 YTD

0

500

1,000

1,500

2018 2019 YTD

CW

C/f

t. (

$)

Avg

. IP

30

/1,0

00

’ (B

OE

D)

+35% -20%

Strong 3Q19 Upper Wolfcamp Performance in Malaga4Q19 activity targeting Red Hills delineation

Upper WC – Upper Wolfcamp horizon

18

Ranger

Red Hills

Malaga

Arrowhead

China

Draw

Eddy

Lea

Strong Upper WC

Productivity & Capital

Efficiency

5 Upper WC

1,850 BOED (62% oil)

365 BOED/1,000’

IP30

4Q19 Red Hills

Delineation

International E&P: Equatorial Guinea

• International portfolio simplified to free cash

flow generating integrated business in E.G.

with close of U.K. asset sale during 3Q

• Total E.G. production of 87 net MBOED

• E.G. EBITDAX1 of $101MM 3Q19 and

$312MM YTD

• E.G. production costs of $1.98 per BOE

during 3Q19

• Third party Alen backfill gas project

progressing on schedule; startup expected

1H21

19

Alba Platform

AMPCO Methanol Plant

EGLNG Loading Dock

1See the 3Q19 Investor Packet at www.Marathonoil.com for Non-GAAP reconciliations

Well Established Track Record of FCF & Return of Capital

20

• Returned ~$1.3B of capital to shareholders since 2018, representing ~25% of operating

cash flow, funded entirely by organic FCF

• Competitive FCF yield despite gas and NGL pricing headwinds

• ~$1.45B of buyback authorization outstanding

• Return of capital included in executive compensation scorecard

$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

ali

ze

d F

CF

Yie

ld (

%)

291

1,000

122

300

169

1,037

420

1,457

700

Avg WTI Price: $65 $57 $62

FCF Yield (Annualized)DividendRepurchasesOrganic FCF before Dividend

FCF Yield = Organic FCF before Dividend / Market Cap (as of 10/31/2019)

Seven consecutive quarters of organic FCF generation

2020 Business Plan Preview

21

• Corporate returns first, sustainable FCF at

conservative pricing, prioritize return of capital

to shareholders, differentiated execution

• 2020 budget planning basis of $50/bbl WTI with

enterprise FCF break-even below that level

• Anticipate total and development capital

spending down year-over-year with U.S. oil

growth moderating; growth expected on year-

over-year and exit-to-exit basis

• Relative capital allocation shifting more to

Bakken & Eagle Ford, supported by resource

base enhancement success; both assets

growing production

• REx program transitions from acreage capture

to exploration, appraisal and delineation

drilling of Texas Delaware and Louisiana

Austin Chalk

Corporate Returns

Free Cash Flow

Return of Capital

Differentiated Execution

Framework for Success Unchanged - Less E&P, More S&P

Appendix

Total Company Cash Flow for 3Q19

• 3Q19 development capital spend of $646MM; Full year $2.4B guidance unchanged

• YTD organic FCF of ~$300MM; YTD stock repurchases of ~$300MM

• ~$1.45B of share repurchase authorization outstanding

• Recent finance transactions extend maturities, generate cash cost savings, demonstrate

commitment to maintaining investment grade credit rating

Generated $81MM of 3Q organic FCF

23

1 Excludes $6MM of exploration costs other than well costs2 Includes proceeds from U.K. and Louisiana Austin Chalk transactions3 Total working capital includes $(21)MM and $3MM of working capital changes associated with operating activities and investing activities, respectively

See the 3Q19 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations

961 1,0421,165

763 646

40

4

35 30

206 18

0

500

1,000

1,500

2,000

6/30/19 Cash

Balance

Operating

Cash Flow b/f

WC

Development

Capital

Expenditures

Dividends EG LNG

Return of

Capital &

Other

Cash Bal b/f

A&D, REx,

Working

Capital &

Financing

REx Capex Share

Repurchase

A&D (Net) Total Working

Capital

9/30/19 Cash

Balance

$M

M

1

3

2

Portfolio Transformation Since 201310 Country Exits

24

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 U.S.

resource plays while materially reducing cash costs

• Portfolio simplification has contributed to an asset retirement obligation reduction of $1.8B since 2014

2019 Production Guidance

4Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

4Q19 3Q19* 4Q18* 4Q19 3Q19* 4Q18*

United States 190 – 200 201 179 320 – 330 338 304

International 12 – 16 15 16 80 – 90 87 93

Total Net Production 202 – 216 216 195 400 – 420 425 397

* Divestiture-adjusted

25

• Full year 2019 divestiture-adjusted oil production growth guidance is now expected to be 11% for

total Company and 13% for U.S., above initial guidance of 10% and 12% respectively

2019 Cost and Tax Rate Guidance

Prior

2019 Guidance

Current

2019 Guidance

United States Cost Data ($ per BOE)

Production Operating $4.50 – 5.50 $4.50 – $5.25

DD&A $18.25 – 20.75 $18.25 – $20.25

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

International Cost Data ($ per BOE)

Production Operating $3.75 – 4.25 $3.75 – $4.00

DD&A $3.00 – 4.00 $3.00 – 4.00

S&H and Other1 $0.75 – 1.25 $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

26

• 2019 U.S. production operating and DD&A unit cost guidance reduced

• 2019 International production operating unit cost guidance reduced

United States Crude Oil DerivativesAs of November 5, 2019

Crude Oil

4Q19 FY 2020 FY 2021

NYMEX WTI Three-Way Collars

Volume (BBLs/day) 80,000 42,945 -

Weighted Avg Price per BBL:

Ceiling $74.19 $65.58 -

Floor $56.75 $55.00 -

Sold put $49.50 $47.77 -

Basis Swaps – Argus WTI Midland (a)

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

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

Basis Swaps – Net Energy Clearbrook (b)

Volume (BBLs/day) 2,000 - -

Weighted Avg Price per BBL $(3.33) - -

Basis Swaps – NYMEX WTI / ICE Brent (c)

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

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

Basis Swaps – Argus WTI Houston (d)

Volume (BBLs/day) 10,000 - -

Weighted Avg Price per BBL $5.51 - -

NYMEX Roll Basis Swaps

Volume (BBLs/day) 60,000 - -

Weighted Avg Price per BBL $0.38 - -

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

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

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

(d) The basis differential price is indexed against Argus WTI Houston27

United States Natural Gas DerivativesAs of November 5, 2019

(a) Between Oct. 1, 2019 and Nov. 5, 2019, we entered into 100,000 MMBtu/day of three-way collars for January - March 2020 with a celing price of $3.32, a floor price of $2.75,

and a sold put price of $2.25

28

Natural Gas (Benchmark to NYMEX HH)

FY 2020

Three-Way Collars (a)

Volume (MMBtu/day) 24,863

Weighted Avg Price per MMBtu:

Ceiling $3.32

Floor $2.75

Sold put $2.25

2019 Capital, Investment & ExplorationBudget reconciliation ($MM)

Development Capital 2019

Budget 1Q19 2Q19 3Q19

2019 YTD

Actual

Cash additions to Property, Plant and Equipment 615 647 672 1,934

Working Capital associated with PPE (1) 54 3 56

Property, Plant and Equipment additions 614 701 675 1,990

M&S Inventory (4) (6) (1) (11)

REx expenditures included in capital expenditures (41) (59) (28) (128)

Exploration costs other than well costs - - - -

Development Capital 2,400 569 636 646 1,851

29

Resource Exploration (REx) Capital 2019

Budget 1Q19 2Q19 3Q19

2019 YTD

Actual

REx expenditures included in capital expenditures 41 59 28 128

Additions to Other Assets and acquisitions (14) (28) 1 (41)

Exploration costs other than well costs 10 6 6 22

REx Capital Expenditure 280 37 37 35 109

• $80MM increase to 2019 REx capital expenditures vs. prior guidance; On a cash basis, EQNR

transaction helps fund incremental REx capital spending relative to prior guidance.