2019 CAPITAL PROGRAM & 2018 RESULTS

February 13, 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, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production, cash margins, 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 2017 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 4Q18 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

3

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

Forward Outlook Prioritizes Returns, FCF, Return of CapitalOrganic FCF positive in both 2019 and 2020 above $45/bbl WTI, post-dividend

4

Corporate Returns

• Continues multi-year rate of change improvement in key enterprise performance metrics

− 20% CROIC and 18% CFPDAS CAGRs (2017-2020) at $50/bbl WTI flat

− 30% CROIC and CFPDAS CAGR (2017-2020) at $60/bbl WTI flat

Free Cash Flow

• Organic FCF positive above $45/bbl WTI in both 2019 and 2020

• Portfolio delivers strong two-year (2019-2020) organic FCF

− >$750MM at $50/bbl WTI flat

− >$2.2B at $60/bbl WTI flat

Return of Capital

• Continue to prioritize return of capital

− Returned over 25% of operating cash flow to shareholders in

2018

− Return of capital metric incorporated into executive

compensation scorecard, complementing CROIC and CFPDAS

Differentiated Execution

• High value oil growth exceeds BOE growth, an outcome of returns-

first capital allocation

− 2019 U.S. oil growth of 12% and total oil growth of 10%

• Maintaining focus on organic resource base enhancement

1Organic 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 2CROIC = 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); 3CFPDAS = Cash flow per debt adjusted share; calculated by taking cash flow (Operating Cash Flow before working

capital + net interest after tax) divided by total shares including debt shares. Debt shares is the average net debt during a calendar year divided by the average

annual stock price; See the 4Q 2018 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations

1

Sustainable FCF in 2019 & 2020 at Conservative PricingDifferentiated annual FCF yield vs. E&P peers

0%

5%

10%

0

500

1,000

1,500

2,000

2,500

2019 - 2020 2019 - 2020 2019 - 2020

Cu

mu

lati

ve O

rgan

ic F

CF

($M

M)

2019 – 2020

($60 WTI)

Organic FCF Organic FCF Yield (Annual Avg.)

$2.2B+

Cumulative

Organic FCF

Org

an

ic F

CF

Yie

ld (

An

nu

al

Avg

.)

$750MM+

Cumulative

Organic FCF

Organic FCF+

Above $45/bbl

in Both Years

2019 – 2020

($50 WTI)

2019 – 2020

($45 WTI)

*Organic FCF yield represents average annualized yield for 2019 and 2020 using MRO stock price as of 2/8/19

5

Differentiated Execution Led the Way in 2018Underpins confidence in 2019 delivery

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

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

22.5% resource play oil

growth at midpoint

32% resource play oil

growth

6

Eagle Ford

Bakken

Oklahoma

Northern

Delaware

Resource Play

Capital Allocation

Resource Play

Development

REx

Other

Focused program balances corporate returns with strategic objectives

• Total capital program of $2.6B, down from 2018

– Comprised of $2.4B development capital and $200MM of resource play leasing and exploration (REx) capital

– Planning basis of $50/bbl WTI; organic free cash flow positive above $45/bbl WTI, post-dividend

• Over 95% of development capital allocated to U.S. resource plays

– ~60% of resource play capital allocated to Eagle Ford and Bakken with ~40% to Oklahoma and Northern Delaware, similar to 2018

– Capital efficient oil growth on flat wells to sales drives corporate returns improvement

– Development capital continues to fund organic resource base enhancement initiatives

• Year-over-year reduction in REx capital reflects more ratable forward spending profile

– Continues progression of LA Austin Chalk and other emerging opportunities with focus on full cycle returns

Focused Investment

7

2019 Capital Program Overview

Appraise / Delineate Early Development Full Field Development

2019 Basin Level Highlights and Objectives

Competitively advantaged multi-basin model

• 85 - 95 gross operated wells to sales

• 90% Myrmidon and Core Hector

• Continue organic enhancement initiatives

• Returns, free cash flow, oil growth

• 55 - 60 gross operated wells to sales

• Focus on Malaga Upper Wolfcamp and

Red Hills delineation

• Transition to multi-well pads

• Returns, oil growth, and margin

enhancement

Northern Delaware

• 55 - 60 gross operated wells to sales

• Development focus on overpressured

STACK and SCOOP; 95% pad drilling

• Secondary target delineation

• Predictability and competitive returns

Oklahoma

• 125 - 135 gross operated wells to sales

• 90% Karnes and Core Atascosa

• Continue organic enhancement initiatives

• Progress multi-well Phase 2 enhanced oil

recovery (EOR) pilot

• Returns and free cash flow

Eagle Ford

Bakken

8

2018 Highlights

Full-year 2018 Highlights

• Delivered capital discipline, corporate returns improvement, free cash flow generation, and enhanced return of capital to shareholders

• Drove capital efficiency improvement leading to high margin oil growth outperformance

• Enhanced resource base through core extension tests in Eagle Ford and Bakken; progressed REx program with focus on full-cycle returns

• 125% reserve replacement at <$12.50/BOE

• Closed $450MM Libya sale; received final Oil Sands Mining payment of $750MM

• Further strengthened balance sheet and financial flexibility by increasing cash and cash equivalents by ~$900MM to $1.5B at YE 2018

4Q 2018 Highlights

• $255MM of organic FCF

• Development capex down 10% sequentially to ~$500MM

• Another quarter of differentiated multi-basin execution and capital efficiency improvement

− Eagle Ford: 38 wells achieved an avg. IP 30 of 1,810 BOED (72% oil)

− Bakken: Ajax four-well pad extension test achieved avg. IP 30 of 2,370 BOED (81% oil) at ~$5MM completed well cost (CWC)

− Oklahoma: 3R SCOOP infill >60% above type curve at 45 days; positive Springer delineation well

− Northern Delaware: 4 Upper Wolfcamp wells avg. IP 30 of 340 BOED/1,000 ft. lateral (74% oil)

9

563

1,431 1,462

3,245

2,286

169

78

369

700

1,151

51

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1/1/18 CashBalance

OperatingCash Flow

b/f WC

DevelopmentCapital

Expenditures

Dividends EG LNGReturn ofCapital& Other

CashBalanceb/f A&D,REx &

Financing

REx Capex Share Buy-Back

Acquisitions&

Disposal ofAssets (Net)

TotalWorkingCapital

12/31/18Cash

Balance

$M

M

12

3

Total Company Cash Flow for 2018

• $2.3B annual development capital budget unchanged throughout year

• $700MM of stock buy-backs and ~$170MM of annual dividend; over 25% of operating cash flow

returned to shareholders in 2018

• $369MM REx Capex more than fully funded by disposition proceeds

Generated ~$865MM of organic free cash flow at avg. WTI of $65/bbl

1 Excludes $34MM of exploration costs other than well costs

2 Acquisition and Disposal of Assets includes $105MM BLM lease costs, Libya disposition & OSM final payment

3Total working capital includes $17MM and $(68)MM of working capital changes associated with operating activities and investing activities, respectively & other

See the 4Q 2018 Investor Packet at www.Marathonoil.com for non-GAAP reconciliations10

Standout Year for Eagle Ford on All Fronts

Full-year 2018 Highlights

• 2018 oil production growth of 7% on 5% fewer

gross operated wells to sales (WTS)

• 40 Atascosa wells achieved avg. IP 30 of 1,510

BOED (72% oil), demonstrating strength of

extended core

• Compelling returns, significant free cash flow

generation, improved well productivity

– 180-day cumulative production up 10% vs. 2017 and

up 45% vs. 2016

4Q 2018 Highlights

• Production averaged 107 net MBOED, up 2%

from year-ago quarter

• 38 WTS with avg. IP 30 of 1,810 BOED (72% oil)

• Completion stages per day up over 10% and

avg. CWC per lateral foot down over 15% vs.

year-ago quarter

Well performance history composed of MRO operated wells across all formations

Well Performance History

Production Volumes and Wells to Sales

0

20

40

60

0

40

80

120

1Q18 2Q18 3Q18 4Q18

Op

era

ted

We

lls

to

Sa

les

Production Gross Wells Net WI Wells

MB

OE

D

0

50

100

150

0 45 90 135 180

2017

2016

2015

Avg

. C

um

. P

rod

ucti

on

(M

BO

E)

Days

2018

Year-over-year growth on fewer wells to sales

11

Strong Well Productivity from the Eagle Ford Core

Guajillo East5 well pad

1,480 BOED (82% oil)

~5,960’ LL

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

Live Oak

Bee

KarnesAtascosa

Wilson

4Q18 Pads

to Sales

CRH / Fire Opal3 well pad

1,800 BOED (73% oil)

~5,500’ LL

Challenger B / Medina H.3 well pad

1,470 BOED (79% oil)

~5,230’ LL

Jordan / Fransen / GM5 well pad

1,550 BOED (69% oil)

~3,270’ LL

San Christoval Ranch3 well pad

1,640 BOED (48% oil)

~3,310’ LLLuna / May

4 well pad

1,480 BOED (56% oil)

~5,750’ LL

Kowalik3 well pad

2,940 BOED (68% oil)

~8,950’ LL

Brown D. / Holland B.6 well pad

2,070 BOED (74% oil)

~6,010’ LL

Medina-Jonas6 well pad

1,940 BOED (83% oil)

~6,750’ LL

4Q 2018 wells driving robust corporate returns

12

~50% Y/Y Capital Efficiency Improvement

1,000

1,500

2,000

2,500

3,000

4Q17 4Q18

BO

ED

IP 30 BOED*

+15%

$4

$5

$6

$7

$8

4Q17 4Q18

CW

C (

$M

M)

CWC ($MM)

-24%

Bakken Performance Consistently Enhancing Value

* IP 30 rates normalized to 9500’.

0

10

20

30

0

20

40

60

80

100

1Q18 2Q18 3Q18 4Q18

Production Gross Wells Net WI Wells

MB

OE

D

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

Successful core extension tests in Ajax, Southern Hector, and Elk Creek

Full-year 2018 Highlights

• Capital efficient oil production growth of 53%

• 20 Northern Hector wells achieved avg. IP 30 of

2,390 BOED (78% oil), demonstrating strength of

extended core

4Q 2018 Highlights

• Production averaged 94 net MBOED, up 37%

from year-ago quarter

• 27 WTS avg. IP 30 of 3,335 BOED (76% oil)

• Ajax four-well pad extension test achieved avg. IP

30 of 2,370 BOED (81% oil) at ~$5MM CWC

• Avg. IP 30 up 15% with CWC down 24% vs. year-

ago quarter

– 8 wells achieved sub $5MM CWC with avg. IP 30 of

2,850 BOED (76% oil)

– Completion stages per day up over 65% from year-

ago quarter

13

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

30-d

ay I

P (

BO

PD

)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

30-d

ay I

P (

BO

PD

)Leading Williston Basin Well Productivity

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

Source: Drilling info, competitor presentations and internal data. External data available through 4Q 2018.

Delivered 45 of the top 50 all-time Middle Bakken & Three Forks oil wells

McKenzie

Dunn

Myrmidon

Hector

Elk Creek

AjaxQ4 2018

to Sales

Axell, Nugget & Ness Pads

9 wells

3,450 BOED

(74% oil)

Irish Pad

3 wells

3,140 BOED

(74% oil)

Ringer Pad

2 wells

2,385 BOED

(84% oil)

Gloria Pad

4 wells

2,370 BOED

(81% oil)

Clara Pad

4 wells

3,510 BOED

(73% oil)

Julia Jones Pad

5 wells

4,250 BOED

(75% oil)

Historic Three Forks Well Performance

Historic Middle Bakken Well Performance

MRO 2018 MRO 2017 Peers

MRO 2018 Peers

14

0

4

8

12

16

20

0

20

40

60

80

100

1Q18 2Q18 3Q18 4Q18

Production Gross Wells Net WI Wells

Enhanced Returns & Predictability Continue in Oklahoma

Full-year 2018 Highlights

• Successful transition to infill development in overpressured STACK and SCOOP

– Competitive returns and predictable results at various spacing designs

• Completion cost per lateral ft. down >30% from prior year

4Q 2018 Highlights

• 67 net MBOED production, up 4% from year-ago quarter

• 8 well per section 3R SCOOP Woodford infill delivered avg. IP 30 of 2,600 BOED(69% liquids)

– CWC/lateral ft. ~35% below most recent SCOOP Woodford infill (Lightner)

– Springer delineation well on same pad delivers IP 30 of 1,825 BOED (81% oil)

• Completion stages per day up 55% from year-ago quarter

3R SCOOP Infill >60% Above Type Curve at 45 Days

0

40

80

120

160

0 15 30 45 60 75

Type Curve

Lightner Wells - 4 wells on 8 wps

3R Wells - 8 wps

MB

OE

D

Days

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

MB

OE

D

15

SCOOP infills outperforming type curve

wps – wells per section spacing

Focused on Overpressured STACK and SCOOP

Caddo

Grady

Stephens

Blaine

Canadian

Kingfisher

Wet Gas

Condensate

Oil

4Q18 Wells to Sales

IPs shown are 30-day (includes oil, NGL and gas) and represent pad average on the 3R, and single well on the Papa Pump

Burton

Ellis

Olive June

Lloyd

Ruthie

Calvin

3R7 Woodford infill wells (8 wps)

2,600 BOED (69% liquids)

~10,000’ LL

Papa Pump1 Springer delineation well

1,825 BOED (81% oil)

~8,480’ LLUpcoming Infills

Multi-well development continues

16

4Q17 4Q18

Stages/day

Full-year 2018 Highlights

• Risked gross company operated locations up

~20% since play entry

• Drilling ft. per day up >20% and completion

stages per day up >30% vs. 2017

• Improved midstream access for all products

4Q 2018 Highlights

• 26 net MBOED production, up 138% from

year-ago quarter

• 12 WTS avg. IP 30 of 1,935 BOED (49% oil),

or 360 BOED per 1,000 ft. lateral

– 4Q activity featured successful Lower Wolfcamp

(WC) spacing test

– 4 Upper WC wells avg. IP 30 of 340 BOED per

1,000 ft lateral (74% oil)

• Executed comprehensive water handling

agreement covering Red Hills area

• Completion stages per day up 40% from year-

ago quarter

Strategically Pacing Northern Delaware

0

5

10

15

20

25

0

5

10

15

20

25

30

1Q18 2Q18 3Q18 4Q18

Production Gross Wells Net WI Wells

Production Volumes and Wells to Sales

Op

era

ted

Wells t

o S

ale

s

Co

mp

leti

on

sta

ges/d

ay

Capturing Significant Efficiency Gains

MB

OE

D

+40%

Focus on multi-well pads while progressing delineation

17

International Highlights

Alba Gas Plant

AMPCO Methanol Plant

EGLNG Plant

World Class Gas Infrastructure

Alba Gas Plant

AMPCO Methanol Plant

EGLNG Plant

Full-year 2018 Highlights

• Production of 113 net MBOED

• E.G. EBITDAX of over $650MM

• Reduced estimated U.K. asset retirement

obligation by $143MM

• Continued rigorous portfolio management

– Closed $450MM Libya sale; received final Oil

Sands Mining payment of $750MM

– Progressing full Kurdistan exit, which will mark 9th

country exit in last 5 years

4Q 2018 Highlights

• Production of 105 net MBOED

– 1Q19 volume guidance includes impact of E.G.

triennial turnaround

• E.G. EBITDAX of $153MM

18

Framework for SuccessPrioritizing Corporate Returns, FCF, Return of Capital to Shareholders

“While many in our industry talked about capital discipline, we delivered… Through improving capital efficiency and

unwavering discipline, we drove significant improvement to our corporate returns, delivered more oil growth, generated $865

million of organic free cash flow post-dividend, and returned most of that cash back to our shareholders via share

repurchases. As we turn to 2019 and beyond, we remain committed to this same framework for success.”

- Lee Tillman, Chairman, President and CEO

• Multi-year CROIC

improvement

• Organic FCF above $45/bbl

• Prioritizing return of cash

• $2.4B development capital

budget

• 10% total company oil growth

& 12% U.S. oil growth

• $200MM REx budget

Our Plan - 2019

• 78% realized CROIC

improvement

• $865MM of organic FCF

• $700MM of share buybacks

• Unchanged $2.3B

development capital budget

• 24% total company oil growth

vs. 18% initial guidance

• $369MM REx spend

Our Delivery - 2018

• Corporate Returns

• FCF Generation

• Return of Capital to

Shareholders

• Differentiated

Execution

Our Framework

Our Foundation

• Multi-Basin Portfolio • Balance Sheet Strength

19

Appendix

20

2019 Production Guidance

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

2019 2018* 2019 2018*

United States 185 - 195 169 320 - 330 295

International 20 - 30 27 90 - 100 110

Total Net Production 205 - 225 196 410 - 430 405

1Q19 Net Production Oil Production (MBOPD) Equivalent Production (MBOED)

Q1 2019 Q4 2018* Q1 2018* Q1 2019 Q4 2018* Q1 2018*

United States 175 - 185 180 160 295 - 305 306 278

International 20 - 30 23 30 85 - 95 102 110

Total Net Production 195 - 215 203 190 380 - 400 408 388

* Divestiture-adjusted, and also excludes Atrush volumes which are held for sale

21

2019 Cost and Tax Rate Guidance

Full-Year Estimate

United States Cost Data

Production Operating $4.50 – 5.50

DD&A $19.25 – 21.75

S&H and Other* $4.00 – 4.50

International Cost Data

Production Operating $4.75 – 5.75

DD&A $3.75 – 5.25

S&H and Other* $1.00 – 1.50

Expected Tax Rates by Jurisdiction:

United States and Corporate Tax Rate 0%

Equatorial Guinea Tax Rate 25%

United Kingdom Tax Rate 40%

* Excludes G&A expense

22

United States Crude Oil DerivativesAs of February 12, 2019

Crude Oil (Benchmark to NYMEX WTI)

1Q 2019 2Q 2019 3Q 2019 4Q 2019 FY 2020

Three-Way Collars

Volume (BBLs/day) 70,000 70,000 50,000 50,000 -

Weighted Avg Price per BBL:

Ceiling $71.21 $71.21 $75.88 $75.88 -

Floor $55.86 $55.86 $57.80 $57.80 -

Sold put $48.71 $48.71 $50.80 $50.80 -

Basis Swaps (a)/(b)

Volume (BBLs/day) 10,000 11,000 16,000 16,000 15,000

Weighted Avg Price per BBL $(0.82) $(1.06) $(1.53) $(1.53) $(0.94)

NYMEX Roll Basis Swaps

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

Weighted Avg Price per BBL $0.38 $0.38 $0.38 $0.38 -

23

(a) The basis differential price is between WTI Midland and WTI Cushing

(b) Between January 1, 2019 and February 12, 2019, the Company entered into 5,000 Bbls/day of Midland basis swaps for July - December 2019 with an average price of $(2.55) and

1,000 Bbls/day of Clearbrook basis swaps for March - December 2019 with an average price of $(3.50)

United States Natural Gas DerivativesAs of February 12, 2019

Natural Gas (Benchmark to NYMEX HH)

1Q19

Three-Way Collars

Volume (MMBtu/day) 200,000

Weighted Avg Price per MMBtu:

Ceiling $5.25

Floor $3.43

Sold put $2.88

24

1Q 2Q 3Q 4Q Full-Year

United States Net Sales Volumes:

- Crude Oil and Condensate (MBD) 164 168 173 180 171

- Natural Gas Liquids (MBD) 50 57 58 55 55

- Natural Gas (MMCFD) 420 435 433 422 429

- United States Total (MBOED) 284 298 303 305 298

International Net Sales Volumes:

- Crude Oil and Condensate (MBD) 35 32 27 29 32

- Natural Gas Liquids (MBD) 11 12 11 10 11

- Natural Gas (MMCFD) 415 461 441 411 430

- International Total (MBOED) 115 121 112 108 114

Total Sales Volumes (MBOED) 399 419 415 413 412

Total Available for Sale (MBOED) 398 419 419 411 412

Equity Method Investment Net Sales Volumes:

- LNG (metric tonnes/day) 5,541 6,141 6,152 5,384 5,805

- Methanol (metric tonnes/day) 1,195 1,316 1,334 1,119 1,241

- Condensate and LPG (BOED) 12,416 12,689 11,942 15,071 13,034

Exploration Expenses (Pre-tax):

- United States ($ millions) 51 64 55 76 246

- International ($ millions) 1 1 1 0 3

Consolidated Effective Tax Rate (ex. Libya) Provision 2% 31% 29% 4% 14%

2018 Volumes, Exploration Expense & Effective Tax RateExcluding Libya

25

4Q 2018 Net Sales Volumes and Realizations

U.S. Divestiture-Adj. Sales Volumes*

MB

OE

D

257

301 305

0

100

200

300

4Q17 3Q18 4Q18

Avg C&C

Realizations

($/BBL)

Excluding Derivatives

$55.46 $68.51 $56.01

Including Derivatives

$54.70 $62.81 $54.51

*U.S. adjusted for divestitures of 5 MBOED in 4Q17 and 2 MBOED in 3Q18

**International available for sale volumes adjusted for divestitures/held for sale of

37 MBOED in 4Q17, 3 MBOED in 3Q18, and 3 MBOED in 4Q18. Sales volumes

adjusted for divestitures/held for sale of 36 MBOED in 4Q17, 4 MBOED in 3Q18,

and 3 MBOED in 4Q18

MB

OE

D

International Divestiture-Adj. Volumes**

117 117 112 108 102 106

0

25

50

75

100

125

4Q 17 3Q 18 4Q 18

Avg C&C

Realizations

($/BBL)***

$54.03 $64.08 $58.25

*** Adjusted the average C&C by $7.29 to exclude Libya in 4Q17

Cumulative underlift of (138) MBOE in E.G., and cumulative

overlift of 6 MBOE in Kurdistan and 68 MBOE in U.K.

SalesAvailable for Sale

4Q17 3Q18 4Q18

26

4Q 2018 Production Mix

58%22%

20% 24%

28%

48%

88%

6%6%

59%18%

23%

Crude Oil/Condensate

NGLs

Natural Gas

Eagle Ford Oklahoma

Bakken

Total U.S.

Resource Plays

54%

19%

27%

Northern Delaware

27

2018 Capital, Investment & ExplorationBudget reconciliation $MM

2018

Budget

2018

Actual

Cash additions to Property, Plant and Equipment 2,753

Working Capital associated with PPE (68)

Property, Plant and Equipment additions 2,685

M&S Inventory (6)

REx expenditures included in capital expenditures (388)

Exploration costs other than well costs (5)

Development Capital 2,300 2,286

28