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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