delivering superior value through the business cycle

Mark W. AlbersSenior Vice President

Barclays Capital CEO Energy/Power ConferenceNew York – September 9, 2009

cautionary statementForward-Looking Statements. Statements of future events or conditions in this presentation or the subsequent discussion period are forward-looking statements. Actual future results, including demand growth and mix; ExxonMobil’s own production growth and mix; the amount and mix of capital expenditures; resource additions and recoveries; finding and development costs; project plans, timing, costs, and capacities; product mix; and the impact of technology could differ materially due to a number of factors. These include changes in long-term oil or gas prices or other market conditions affecting the oil and gas industries; reservoir performance; timely completion of development projects; war and other political or security disturbances; changes in law or government regulation; the outcome of commercial negotiations; unexpected technological developments; the occurrence and duration of economic recessions; unforeseen technical difficulties; and other factors discussed here and under the heading "Factors Affecting Future Results" in the Investors section of our Web site at exxonmobil.com. Frequently Used Terms. The terms “resources,” “resource base,” and similar terms include quantities of discovered oil and gas that are not yet classified as proved reserves but that are expected to be ultimately recovered in the future. Reserves in this presentation are calculated using ExxonMobil’s definition of proved reserves, which assumes the long-term pricing basis that the corporation uses to make its investment decisions. This differs from the SEC basis, which (effective 01/01/2010) is based on 12-month average prices. Reserves herein (i) include proved reserves from oil sands operation in Canada, consistent with the 01/01/2010 revisions to the SEC’s rules; and (ii) are the combined total from both consolidated subsidiaries and our interest in equity companies. Reserves replacement ratio for a given period is calculated utilizing proved oil-equivalent reserves additions (calculated based on ExxonMobil’s definition of proved reserves) divided by oil-equivalent production. For definitions of, and SEC Reg G information regarding, reserves, return on average capital employed, normalized earnings, cash flow from operations and asset sales, and other terms used in this presentation, see the "Frequently Used Terms" posted on the Investors section of our Web site. The Financial and Operating Review on our Web site also shows ExxonMobil's net interest in specific projects.

proven business model

recent business environment

• volatile commodity prices and margins

• changing near-term demand

• significant financial market changes

• adjustments by competitors to business plans

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

1970 1975 1980 1985 1990 1995 2000 2005

UK

'70 '75 '80 '85 '90 '95 '00 '05

%25

20

15

10

5

0

-5

-10

economic cycles

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

1970 1975 1980 1985 1990 1995 2000 2005

USA

GDP* change (quarter vs. quarter)

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

1970 1975 1980 1985 1990 1995 2000 2005

Japan

*gross domestic productSource: U.S. Bureau of Economic Analysis; UK Office for National Statistics; Japanese Cabinet Office

'70 '75 '80 '85 '90 '95 '00 '05

'70 '75 '80 '85 '90 '95 '00 '05

%25

20

15

10

5

0

-5

-10

%

-15

15

10

5

0

-5

-10

cost cycles

-10%

0%

10%

20%

30%

40%

50% oilembargo

asianfinancial

crisis

oil pricesurge

oil pricedrop

gulfwar

annual change in total erected cost – U.S. onshore

'70 '75 '80 '85 '90 '95 '00 '05

%

40

30

20

0

-10

Source: ExxonMobil projects

10

50

0

50

100

150

200

250

300

350

growing demand for energyenergy demand

MBDOE

gas

oil

wind, solar & biofuelsbiomass, hydro & geothermal

nuclear

coal

average growth / year 2005 – 2030

1.2%

Source: The Outlook for Energy: A View to 2030, ExxonMobil, December 2008

0

50

100

150

200

250

300

350

'80 '05 '30

0

30

60

90

120

'300

30

60

90

120

'80 '05 '30

global liquids supply and demand

average growth / year 2005 – 2030

1.0%

~28

OPEC Crude

~38

Liquids Demand

Non-OPEC Crude &

Condensate

Non-OPEC Oil Sands

NGL, OPEC Condensate, Other

Biofuels

Source: The Outlook for Energy: A View to 2030, ExxonMobil, December 2008

MBDOE

average growth / year 2005 – 2030

1.0%

0

20

40

60

80

100

120

gas supply and demand

Source: The Outlook for Energy: A View to 2030, ExxonMobil, December 2008

BCFDNorth America

'05

Conventional

Unconventional

LNG

Local Production

0

20

40

60

80

100

120

'00 '30

0

20

40

60

80

100

120

0

20

40

60

80

100

120

'00 '30

gas supply and demand

Source: The Outlook for Energy: A View to 2030, ExxonMobil, December 2008

BCFDEurope

'05

Conventional

Unconventional

LNG

Pipeline

average growth / year 2005 – 2030

0.9%

0

20

40

60

80

100

120

0

20

40

60

80

100

120

'00 '30

gas supply and demand

Source: The Outlook for Energy: A View to 2030, ExxonMobil, December 2008

BCFDAsia Pacific

'05

Conventional

Unconventional

LNG

Pipeline

average growth / year 2005 – 2030

3.7%

keys to success

• business risk management

• financial strength and flexibility

• asset quality and diversity

• disciplined and consistent business approach

• long-term perspective

ExxonMobil - industry leadership

through the business cycle

organizational effectiveness

• global functional organization implemented at the merger

• unrelenting focus on efficiency and effectiveness

0

20

40

60

80

100

120

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

ExxonMobil Corporation employees (number)*

'99 '00 '01 '02 '03 '04 '05 '06 '07 '08

*regular employees at year-end

thousands

capturing quality growth opportunities

0

20

40

60

80

'03 '08

millionacres

AmericasEurope, Africa

net exploration acreage

42% increase in net exploration acreage from 2003 to 2008

Asia, Middle East, Russia

unconventional gas resource example acquisition cost* (unit cost)

entry cost (U.S. $ per acre)

*competitor entry cost data based on publicly announced deals

reso

urce

den

sity

(oil-

equi

vale

nt b

arre

ls p

er a

cre)

10x l

ess e

xpen

sive

$0.1

0 / O

EB

Refere

nce

$1 /

OEB

10x m

ore e

xpen

sive

$10 /

OEB

1,000

10,000

100,000

10 100 1,000 10,000 100,000

ExxonMobil EntryCompetitor Entry

10x l

ess e

xpen

sive

$0.1

0 / O

EB

Refere

nce

$1 /

OEB

10x m

ore e

xpen

sive

$10 /

OEB

1,000

10,000

100,000

10 100 1,000 10,000 100,000

ExxonMobil EntryCompetitor Entry

reso

urce

den

sity

(oil-

equi

vale

nt b

arre

ls p

er a

cre)

10x l

ess e

xpen

sive

$0.1

0 / O

EB

Refere

nce

$1 /

OEB

10x m

ore e

xpen

sive

$10 /

OEB

1,000

10,000

100,000

10 100 1,000 10,000 100,000

ExxonMobil EntryCompetitor Entry

10x l

ess e

xpen

sive

$0.1

0 / O

EB

Refere

nce

$1 /

OEB

10x m

ore e

xpen

sive

$10 /

OEB

1,000

10,000

100,000

10 100 1,000 10,000 100,000

ExxonMobil EntryCompetitor Entry

consistent reserves replacement

0

50

100

150

1994 1996 1998 2000 2002 2004 2006 2008

%

*Calculated on ExxonMobil definition of proved reserves, assumes long-term pricing basis that the corporation uses to make its investment decisions, and includes proved reserves from oil sands operations in Canada. Includes asset sales.

'94 '04'96 '06'98 '08'00 '02

proved reserves replacement ratio*

adding reserves at lower cost

0

5

10

15

20

XOM BP RDS CVX

'04-'08 reserves replacement cost*$ per OEB

*costs incurred in property acquisition and exploration plus development activities, divided by proved oil-equivalent reserves additions, including purchases. Competitor data estimated on a consistent basis with ExxonMobil, and based on public information. Reserves calculated using year-end pricing; includes Canada oil sands; excludes asset sales.

132% 115% 96% 101%Reserves Replacement

Ratio ’04-’08

0

50

100

150

upstream project execution

schedule performance

114%103%

0

50

100

150

116%105%

variance: actual versus funded (%), '04 to '08 start-ups

cost performance

ExxonMobil operated operated by others

variance: actual versus funded (%), '04 to '08 start-ups

80

85

90

95

100

maximizing value of assetsupstream operations uptime, '04 to '08

93%91%

ExxonMobil operatedoperated by others

%

0

50

100

150

200

1965 1975 1985 1995 2005

cold lake recovery estimatesproduction kbd

13 17 25 30+recovery factor %

'65 '75 '85 '95 '05

disciplined cost management

100

150

200

250

2004 2005 2006 2007 2008

RDS

BPCVX

XOM

cash costs per OEB, indexed* (FAS69)

RDS

BPCVX

XOM

*Upstream technical costs (FAS69) normalized using 10-K/20-F information

'04 '05 '06 '07 '08

industry-leading volumes per share

90

100

110

120

130

140

'04 '05 '06 '07 '08

*competitor data estimated using a consistent basis with ExxonMobil, and based on public information

reserves per share, indexed*

XOM

BP

RDSCVX

90

100

110

120

'04 '05 '06 '07 '08

production per share, indexed*

XOM

BP

RDS

CVX

0

5

10

15

20

XOM CVX RDS BP

industry-leading upstream earnings'04-'08 upstream net income per barrel*

$ / OEB1H 2009

*competitor data estimated on a consistent basis with ExxonMobil, and based on public information

CVX RDS BPXOM

industry-leading upstream returns

0

20

40

60

XOM BP RDS CVX

return on average capital employed*%

average capital employed*$B

0

20

40

60

80

XOM BP RDS CVX

reported net income*$B

0

10

20

30

40

XOM BP RDS CVX

*competitor data estimated on a consistent basis with ExxonMobil, and based on public information

'04 '08

key exploration wells

2009

2010+

Brazil

Canada Orphan

Madagascar Australia

U.S. Gulf of Mexico

Angola

Nigeria Indonesia Cepu

Libya

Indonesia Makassar

New Zealand

UK North SeaGermany

Canada BeaufortWest Greenland

Ireland

Philippines

Hungary Black Sea

Canada Horn River

3 new deepwater rigs under contract

0

25

50

75

100

125

project stage Geography

significant global project portfolionumber of projects (YE '08)

operating

executing

defining

planning /selecting

Middle East

Americas

Europe

Africa

Russia / Caspian

Asia Pacific

project stage geography

0

300

600

900

1200

1500

'08 '09 '10 '11 '12 '13 '14 '15

KOEBD, net2010+ major project start-ups

2010+ start-ups

long-plateau volumes build-up

2009 start-ups

2008 start-ups

other flowstreamslong-plateau volumes

0

300

600

900

1200

1500

'08 '09 '10 '11 '12 '13 '14 '15

AKG Ph 2, Qatargas 2 Train 5, RasGas Train 6 & 7

Qatargas 2 Train 4, East Area NGL II

Kearl Ph 1

PNG LNG Kashagan

KOEBD, net

future capacity growth

Piceance project• commercialize world-class resource through execution excellence

– technology application

– manufacturing efficiencies

– leveraging ExxonMobil global best practices

Qatar LNG projects1999

• startup of world’s largest trains- Qatargas 2 Train 4 & RasGas Train 6

• largest LNG ships delivered

• South Hook and Adriatic LNG terminals commissioned

• remaining startups– Qatargas 2 Train 5– RasGas Train 7– Al Khaleej Gas

Qatargas 2009

RasGas 2009

0

2000

4000

6000

8000

10000

0 20 40 60 80 100 120 140 160 180 200Distance (miles)

Elev

atio

n (f

t)

onshore pipeline elevation profile

PNG gas projectExxonMobil strengths:• execution in challenging environment• developing national content• global gas marketing capability• enabling external project financing

Hides Gas Hides Gas Conditioning Conditioning PlantPlant

long-term commitment to research

commercial applications

identifiedopportunities evaluation

Fast Drill Process

Controlled Freeze ZoneTM

EMColdFlowTM

Advanced Subsurface Imaging LNG technologies

Shale Gas Pore Network Characterization

5

4

3

2

1

00

1

2

3

4

5

'08 '09 '10 '11 '12 '13

profitable production growthtotal production outlook

0

1

2

3

4

5

'08 '09 '10 '11 '12 '13

MOEBD, net

liquids

gas conventional flow streams

extended plateau

Upstream business well positioned

• highest standards of integrity

• largest, high-quality resource portfolio

• lowest life-cycle cost, exploration to production

• disciplined use of global best practices ensuring continuous improvement

• proprietary suite of industry-leading technologies

• attractive growth opportunities

. . . to deliver superior value through the business cycle