investor relations – february 2008 · investor relations - - 3c2041 performance among the best of...

2007 results and outlook

Investor Relations – February 2008

Investor Relations - www.total.com - 3C2041

Performance among the best of the majors

Dividend increased by 11% in euros, or 23% in dollars**

* excluding portfolio changes, price effect, impact of OPEC reductions and shutdowns in Nigeria** 2007 dividend pending approval at the May 16, 2008 Annual Meeting (dollar amount based on 1 € = 1.45 $ at expected payment date

for the remainder of the dividend, May 23, 2008)*** adjusted net income expressed in dollars ; estimates based on public data for other majors

Production

Results***(2007 vs 2006)

1

%

TOT XOM

RDS BP

CVX

5

-5

-10

10

Adjusted net incomeEPS

-15

Production growth : +1.5% to 2.39 Mboe/d+4.5% underlying growth*

Adjusted net income : +6% to record 16.7 B$

Capex : 16.1 B$

Net cash flow : +27% to 10.3 B$

Progressive sale of Sanofi shares started end-2007

TOT

XOM RDS BPCVX

%

1Q07 vs 1Q062Q07 vs 2Q063Q07 vs 3Q064Q07 vs 4Q06

-4

-2

2

4


Successful growth strategy

2 billion boe of potential reserves added in 2007thanks to exploration and business development*

1 Bboe added through exploration

> 50 new permits in 10 countries

Signature of 2 major agreements for the long term

Ongoing portfolio optimization

Launching development of 6 development projects, 2 desulphurization units and Port Arthur coker

Successfully launched major Total-operated projects

Concluded negotiations on Sincorand Kashagan

Main achievements since start of 2007

Arzew ethane cracker

Shtokman Phase I

Port Arthur coker

Kashagan agreement

Conversion of Sincor Rosa

DolphinSisi Nubi

Angola LNGPazflor

Jura HDS LeunaHDS Lindsey

Anguille

Ofon IIUpstream-Downstream Swap

Sale of Interconnector

Sale of 10% of Joslyn

Sale of Milford Haven

2

* including contribution from Shtokman Phase I

CO2 capture pilot project


Major axes of value creation for the long term

Priority to safety and preservation of the environment

Sustain long-term production growth

Consolidate European refining, modernize Port Arthur, and pursue Jubail refinery project in Saudi Arabia

Concentrate European and US petrochemicals on major integrated sites. Growth from projects based on ethane and in Asia

Targeted industrial developments in new energies for the long term

Portfolio optimization (Sanofi-Aventis…)

Developing strategic partnerships and maintaining technological leadership

* growth target based on 60 $/b Brent environment, excluding portfolio changes** including net investment in equity affiliates and non-consolidated companies, excluding acquisitions and based on 1 € = 1.50 $ for 2008(e)

Hydrocarbon production

Capex by segment**

2007 2008(e)

19 B$

16 B$Chemicals

Upstream

Downstream

3

10(e) 12(e)

60$/b80$/b

06 07 15(e)

+4% per yearon average for 2006-2010(e)*

2.5

1.5

0.5

3.5

Mboe/d

08(e)

Results

Investor Relations


Environment

2007 adjusted EPS : +8% expressed in dollars

adjusted income defined as income at replacement cost, excluding special items and Total’s equity share of the amortization of intangible assets related to Sanofi-Aventis merger

* dollar amounts converted from euro amounts using the average €-$ rate for the period

Average hydrocarbon price ($/boe) 65.7 49.6 +32% 55.2 51.9 +6%

Refining margin indicator TRCV ($/t) 30.1 22.8 +32% 32.5 28.9 +12%Average exchange rate €-$ 1.45 1.29 -11% 1.37 1.26 -8%

4.6 3.5 +34% 16.8 15.5 +8%

Adjusted net income 4.5 3.5 +28% 16.7 15.8 +6%

Adjusted EPS ($) 1.99 1.54 +29% 7.35 6.83 +8%

20062007 %4Q064Q07 %in billions of dollars*

20062007 %4Q064Q07

20062007 %4Q064Q07 %in billions of euros

3.2 2.7 +19% 12.2 12.4 -1%

Adjusted net income 3.1 2.7 +14% 12.2 12.6 -3%

Adjusted EPS (€) 1.37 1.20 +15% 5.37 5.44 -1%

%

Adjusted net operating incomefrom business segments

Adjusted net operating incomefrom business segments

4

80

100

1.30

1.50

60

20072006

Brent

Average realized hydrocarbon price of Total

FX rate

$/boe €-$

1.40

40 1.20


Improved performance thanks to growth

Strong sensitivity to favorable environment Benefit of growth and productivity substantially larger than cost increase

Adjusted net operating income from segments (B$)

* tax on adjusted net operating income / (adjusted net operating income – income from equity affiliates, dividends received from investments and amortization of goodwill + tax on adjusted net operating income)

5

Average realized hydrocarbons price : 55 $/boe

TRCV : 32 $/t

Average tax rate* : 56%

2006Average realized hydrocarbons price : 52 $/boe

TRCV : 29 $/t

Average tax rate* : 56%

2007

15.516.8+0.95 (0.50) +1.20(0.35)

Downstream

Upstream

Chemicals

Environment

Upstream +1.1Downstream-Chemicals (0.15)

ExplorationCosts

Including new projects

Growth and productivity

Upstream +0.85Downstream-Chemicals +0.35


High quality portfolio generating solid results

* adjusted results ; estimates for other majors based on public data

Downstream and Chemicals net operating income* ($)

Upstream net operating income* ($)

Upstream portfolio highly leveraged to environment

Downstream and Chemicals robust in a volatile environment

EPS* ($)

2004 2005 2006 2007

160

130

RD Shell

ExxonMobilTotalChevron

BP

base 100

Chevron

ExxonMobil130

2004 2005 2006 2007

BP

RD Shell Total

base 100

70

6

2007

Chevron

Total

ExxonMobil

BP

RD Shell

2004 2005 2006

130

160

base 100


Investment program(Capex / Capital Employed)

Profitability(ROACE*)

Substantial investment program and disciplined capital management

* profitability of business segments ; estimates for other majors based on public data

Capex level commensurate with sustained long-term growth

Continuity of Capex program Share of non-producing assets in capital employed approx. 20% at end-2007

20

ExxonMobil

Chevron

BPRD Shell

Total

%

2004 20072005 2006

25

15

Total

ExxonMobil

RD ShellBP

2004 20072005

Chevron

2006

30

20

%

40

7


2007 adjusted cash flow : +12% to 24 B$

Cash flow allocation (B$)

* cash flow at replacement cost before change in working capital

Net investments increased by 16%Favoring dividend for return to shareholders Working capital increase with higher crude price

Change inworking capital

and net debt

Dividends +20%

Investments +8%

Adjusted cash flow*

2007

Share buybacks -53%

2006

Divestments

Net-debt-to-equity ratio

Gearing maintained around 25-30%Sold 0.4% of Sanofi in 4Q 2007Bought back 1.4% of shares in 2007

Cash flow allocation balanced between reinvesting for future growth and returning value to shareholders

8

15

20

25

30

40

%

20072006

35


2007 dividend : +11% to 2.07 € per share

Best dividend growth among the majors+23% in dollars for 2007

Pay-out ratio (based on dollars)

Dividend(based on $/share)

estimates for other majors based on public data2007 dividend pending approval at the May 16, 2008 Annual Meeting (dollar amount based on 1 € = 1.45 $ at expected payment datefor the remainder of the dividend, May 23, 2008)

180

140

base 100

2004 20072005 2006

+21% per year on average

ExxonMobil

Chevron

BP

RD Shell

Total ($)

Total (€)

ExxonMobil

Chevron

BP

RD Shell

Total

30%

2004 20072005 2006

40%

20%

50%

9


Upstream

Investor Relations


Upstream strategy based on operational excellenceDalia (40%) Rosa (40%) Dolphin (24.5%)

Ability to manage major growth projectsTechnological expertise : deep offshore, heavy oil, LNG, sour gas, HP/HT…Strong discipline in project management

Intensive exploration and development to optimize resource recovery

Alwyn/Jura, Mahakam, Bongkot, Anguille, Angola LNG…

Benefit of historical leadership in major petroleum basinsWest Africa, Middle East…

Accessing new resources through innovative contractual schemes and strategic partnerships

Ichthys LNG, Shtokman, deep-offshore Angola Blocks 17/06 and 15/06…

Plateau : 500 kboe/d340 kboe/d early 2008Ramping up to 2 Bcf/din 1H08

Plateau : 240 kb/d reached in 2Q07

Plateau : 150 kb/dFPSO Girassol : 265 kb/d early 2008

Production from the 3 major 2007 projects*

* Total share ; Dalia start-up December 2006

10

(Dalia, Rosa, Dolphin)kboe/d

50

100

150

200

Dec.2006

June2008(e)

Dec.2007


Success of profitable growth strategy in 2007

Upstream adjusted net operating income (B$) Upstream adjusted net operating income of the majors ($/boe)*

Continuing to improve the competitiveness of Upstream

* estimates for other majors based on public data** tax on adjusted net operating income / (adjusted net operating income – income from affiliates, dividends from investments,

and impairments of acquisition goodwill + tax on adjusted net operating income)

Upstream ROACE : 34% in 2007

Average realized priceLiquids: 69 $/bGas : 5.4 $/mbtu

Hydrocarbon : 55 $/boe

Average tax rate : 60%**

Average realized priceLiquids : 62 $/bGas : 5.9 $/mbtu

Hydrocarbon : 52 $/boe

Average tax rate : 61%**

11

+1.1+0.85

10.9

12.1(0.35)

20072006

CostsNew projectsInflation

Equity affiliates

(0.4)

Environment Volumes Exploration

Total

Chevron

BP

RD Shell

ExxonMobil

base 100

150

2005 200720062004


Large contribution from new production

Best production growth among the majors in 2007

2007 production : +1.5% Impact on income* : +7.5%

changes relative to 2006* impact of 2007 production growth on Upstream adjusted net operating income

** impact of changing hydrocarbon prices on production entitlements

Portfolio changesNigeria shutdowns

Underlying growth

OPEC reductionsPrice effect**

Production growth

12

-0.25 B$

+1.10 B$

Income impact*

-3

6

0

%

9

3Nkossa

New production

Decline and other

Portfolio changesNigeria shutdownsOPEC reductions

Price effect**

Underlying growth : +4.5%

-3%2.36

2.39

Mboe/d

2.2

2.3

20072006


Upstream leveraged to environment

Upstream results* vs hydrocarbon prices (2003-2007)

Sensitivity to oil price(for a change of 1 $/b of Brent)

Results* by type of contract

Reduction in the weight of fixed margin production

Production from new projects highly accretive to results

Approx. one-third of production from PSCs

Less than 30% of PSC production subject to threshold tests

* adjusted net operating income ; sensitivity of results(e) based on 2006-2008 budgets** production sensitivities(e) for 40-60 $/b and 60-80 $/b based on historical data ; production sensitivity for 80-100 $/b based on 2008 budget

Production sharing contracts offer a balanced split of economic rents

PSCConcessions Per technical barrel

13

60-80

Impact on productionin kboe/d**

Impact on results* in M$

40-60 80-100Brent in $/b

-5.0

-3.0

-1.0

200

0

$/boe

10

20

2004 2005 2006 2007604020

5

15

$/boe

80 $/boe

Results vs Brent

Results vs average hydrocarbon price


Total’s competitive advantage on technical costs

* FAS 69, consolidated subsidiaries, estimates for other majors based on public data

Technical costs*Technical costs* vs. Brent

High quality asset portfolio and strict management discipline

14

DD&A

Opex

Explo

12.4

9.9

2006 2007

FX and price effect

Inflation and other

Explo+0.4

+1.0+0.5

DD&A fornew projects

+0.3

$/boe

+0.3

Maintenance

Brent

Other majors

Total

70

50

30

10

$/boe

2004 2005 2006 2007


1 billion boe added from exploration in 2007

* reserve potential added from exploration** 2007 average discovery cost : outlays for exploration and appraisal divided by additions to reserve potential from exploration for the year

(discoveries, revisions and appraisals)

Average discovery cost of 1.7 $/boe** Sustained exploration effort in 2008(e) : 1.8 B$

Block 32

Block 14

Egina

Moho North

MTPS

Tormore

Kessog

Bongkot

Shah Deniz

MahakamExploration in 2007

1

2

3

4

5

Bboe*

2003

2004

2005

2006

2007

In production

In development

Projects in preparation

Appraisal

New permitsDiscoveries & positive appraisals

Rapid confirmation of projects discovered through exploration Numerous exploration successes in 2007

15


Strong positions on majority of growth basins

* limited to proved and probable reserves at year-end 2007 covered by E&P contracts on fields that have been drilled and for which technical studies have demonstrated economic development in a 60 $/b Brent environment, also includes Joslyn tar sands to be developed with mining

** proved and probable reserves plus reserves potentially recoverable from known accumulations (SPE - 03/07)

Increasing portfolio diversification13 countries with more than 500 Mboeof proved and probable reserves at end-2007 compared to 9 at end-200318 countries with more than 500 Mboeof resources**

Conversion of Sincor

Significant additional resources in Russia and heavy oil

Adding acreage in major oil & gas basins

Proved and probable reserves* : 20 Bboe

Portfolio offers good risk-reward balanceSignificant potential for long-term growth

Norway

Kazakhstan

Angola

Nigeria

Canada

United Kingdom

Qatar

≥ 1 Bboe 0.5 - 1 Bboe ≤ 0.5 Bboe

VenezuelaUAE

IndonesiaYemen

Congo

Australia

16


2007 reserve replacement

* reserves of consolidated subsidiaries (FAS 69) and share of equity affiliates and non-consolidated companies** limited to proved and probable reserves at year-end 2007 covered by E&P contracts on fields that have been drilled and for which technical

studies have demonstrated economic development in a 60 $/b Brent environment, also includes Joslyn tar sands to be developed with mining*** proved and probable reserves plus reserves potentially recoverable from known accumulations (SPE - 03/07)

Maintain proved reserve life of 12 years and proved and probable reserve life over 20 years

Proved reserves* Reserves and resources(at December 31, 2007)

17

12 years > 20 years

Proved reserves*

Proved reserves and probable

reserves**

Bboe

> 40 years

Resources***60 $/b

60 $/b90 $/b

40

30

20

10

12/31/2006

Production

Divestments incl. Sincor

Newadditions

Bboe

12/31/2007

Business development

Exploration

Priceeffect

Brent : 58.93 $/b11.1 Bboe

Brent : 93.72 $/b10.4 Bboe

23%

Reserve replacement

rate

102%78%

12

10

8


Outlook for sustained production growth over the long term

* production growth target in a 60 $/b Brent environment, excluding portfolio changes** operated by Total or through an operating company

*** reduction of interest in Kashagan from 18.5% to 16.8%, pending finalization of agreements ; participation in Tormore of 47.5%

Hydrocarbon production

Estimated base decline rate of 3-4% per year on average

Price effect between 60 $/b and 80 $/b Brent on the order of 50 kboe/d in 2010(e)

Victoria Liq/Gas Study 40% ApprecShtokman Ph. I LNG/pipe Study 25% Study Shah Deniz FF Gas 475 10% Study Pars LNG LNG 300 30% Study Kashagan Liquids 1,500 16.8% Study Joslyn mining Heavy oil 2x100 74% StudySurmont Ph. 2 & 3 Heavy oil 170 50% Study Sulige Gas Study 100% ApprecBlock 32 Deep offshore Study 30% Study CLOV Deep offshore Study 40% Study Moho North Deep offshore Study 53.5% Study Ichthys LNG LNG 335 24% Study Brass LNG LNG 300 17% FEEDEgina Deep offshore 200 24% Study NLNG T7 LNG 250 15% FEEDLaggan/Tormore Liq/Gas 90 50% FEED Angola LNG LNG 175 13.6% DevKashagan Exp Ph. Liquids 330 16.8% DevUsan Deep offshore 180 20% DevPazflor Deep offshore 200 40% DevBongkot South Gas 70 33.3% EPC Anguille redev. Liquids 40 100% DevTempa Rossa Heavy oil 50 50% Dev

2007

2008(e)

2009(e)

2010(e)

2012-2015(e)

2011-2012(e)

Projects ShareCapacity(kboe/d)

Tyrihans Liquids 70 23.2% DevOfon II Liquids 100 40% DevTombua Landana Liquids 130 20% DevTahiti Deep offshore 135 17% DevQatargas II (T2) LNG 250 16.7% DevAkpo Deep offshore 225 24% DevYemen LNG LNG 195 39.6% DevJura Liquids 45 100% DevMoho Bilondo Liquids 90 53.5% Dev

NLNG T6 LNG 120 15% ProdWest Franklin Liquids 20 46.2% ProdSisi Nubi LNG 70 47.9% ProdSnøhvit LNG 120 18.4% ProdDolphin Liq/Gas 500 24.5% ProdSurmont Ph. I Heavy oil 25 50% ProdRosa Deep offshore 150 40% Prod

Op**

***

***

Status

***

18

2.5

1.5

0.5

3.5

Mboe/d

2006 2007 2010(e) 2012(e) 2015(e)

Share of technical production

+4% per year on average

for 2006-2010(e)* 60$/b80$/b


80% of new production through 2010 operated by Total

* estimates based on Brent at 60 $/b in 2008 and thereafter, Total share ** at 1/01/2008

Plateau : 90 kboe/dStart-up : 2Q08(e)Progress : approx. 95%**

Plateau : 45 kboe/dStart-up : 2Q08(e)Progress : approx. 70%**

Plateau : 225 kboe/dStart-up : winter 08-09(e)Progress : approx. 65%**

Plateau : 195 kboe/dStart-up : winter 08-09(e)Progress : approx. 70%**

Yemen LNG (39.6%)

Akpo (24%)

Jura (100%)

Plateau : 250 kboe/dStart-up : 1H09(e)Progress : approx. 45%**



Qatargas II TB (16.7%)Tahiti (17%) Tombua Landana (20%) Ofon II (40%)

Plateau : 100 kboe/dStart-up : 2010(e)Progress : approx. 5%**

Moho Bilondo (53.5%)

19

Production from main projects 2007-2010(e)*

Dalia, Rosa, Dolphin

Moho, Jura

Yemen LNG, Akpo, Qatargas II, Tahiti, Tombua Landana, Ofon II…

2007 2008(e) 2009(e) 2010(e)

kboe/d

600

400

200

2010(e)

Total-operated

Non-operated


Diversified human resource base adapted to long-term growth target

Skilled and loyal workforce deeply rooted in local environment

* as of January 1, 2007** Capex for development, excluding downstream gas and new energies

Exploration & Production subsidiaries(2007 data)

80% of new hires into managerial positions goinginto geoscience and operations :

3,000 new hires between 2007 and 2012(e)

Proportion of local nationals in management of subsidiaries at 65% in 2007 and continuing to grow

Growing importance of trainingEnhancing technical skillsIncreasing internationalization of workforce Promoting strategic partnerships

Attrition limited to approx. 2% per year on average

20

Africa

AsiaMiddle East

EuropeCentral Asia

Americasbase 100

Workforce* Production Capex**

Geosciences

Operations

Management

Support


Upstream - LNG and New Energies

Investor Relations


Diversified and well-positioned portfolio of LNG assets

Global LNG demand growth : 10% per year on averageTotal’s growing arbitrage capacity allows it to capture the most attractive prices

LNG production by origin in 2015(e)

LNG salesby destination in 2015(e)

Total’s LNG projectsliquefaction plants under study liquefaction plants existing

or under constructionregas facilities

European demand

+12% / year

Asian demand

+5% / year

North Americandemand

+25% / year

Main LNG consuming markets

LNG producing countries in 2015(e)

Total estimates for global LNG demand, production and sales* sales, Group share, excluding trading

21

Total’s portfolio

Worldwide production

Asia

Middle East

Atlantic Basin

base 100

50

North America

Asia

Europe

Total’s portfolio*

Worldwidemarket

base 100

50

06 15(e)

95 Mt

06 15(e)

115 Mt

165 Mt

06 15(e)


Significant potential for value creation in LNG

Convergence of spot and long-term gas prices in Europe on averageStrong seasonal price volatility in the Atlantic Basin and effective arbitrage with LNGAsian markets tight in a context of strong demand growth

* Atlantic Basin prices based on internal estimates ; Asian market estimates based on representative long-term contracts

Middle East netback on LNG contracts*

Close to 20% of Upstream net operating income and capital employed in 2007Growing contribution from LNG to the profitability of Total

Profitability of Total’s LNG portfolio

B$

Average non-producing capital employed

Average producing capital employed

2004 2007

6

4

2

Net operating income

before2000

in2003

in2006

in2007

Estimated mid-term prices

22

US EU

$/mbtu

Atlantic Basin

Asian market

Contracts signed

80 $/b

60 $/b

14

10

6


Ichthys LNG (24%)

Capacity : 8.4 Mt/yFID 2008-2009(e)Asia

Changing scale of Total’s LNG portfolio

* sales, Group share, excluding trading ; estimates for other majors

Took 25% interest in Shtokman Phase I

Launched development of Angola LNG

Development of Yemen LNG on track

Started production on Snøhvit and NLNG T6

LNG sales*

Yemen LNG (39.6%)

Capacity: 6.7 Mt/yStart-up winter 08-09(e)US, Asia

Qatargas II TrB (16.7%)

Capacity : 7.8 Mt/yStart-up 2009(e)Europe, US

Brass LNG (17%)

Capacity : 10 Mt/yFID 2008-2009(e)US, Europe

Shtokman (25%)

Capacity : 7.5 Mt/yFID 2009(e)US, Europe

Major LNG producer with approx 17% of Group production in 2010(e)

Important developments since the start of 2007

Capacity : 8.5 Mt/yFID 2008-2009(e)US

NLNG T7 (15%)

Capacity : 5.2 Mt/yFID Dec. 2007US

Angola LNG (13.6%)

23

2006 base

2010(e) growth projects

2015(e) growth projects

2006 2010(e) 2015(e)

+13% per year on average(e)

Total

Mt/y

20

10

30

RDS XOM BP CVX


Progressively expanding Total’s energy offerings

Growing new energies business in context of high hydrocarbon prices

Complementary to hydrocarbon value chain Demonstrated ability to manage major projects and master new technologiesAcceptable returnsSharing expertise with other industrial players

Strengthening position in solar Increasing production of photovoltaic cells (Photovoltech)

Proposing nuclear projects in oil producing countries

Accelerating R&D Clean coal and XTL, second-generation biomass and CO2 sequestration

Photovoltaic cell production capacity* (Photovoltech)

Carbon-free energies

* at year-end for each period ; Photovoltech is a 47.8% owned subsidiary of Total** megawatt peak, equivalent to one million peak watts

Outlook for technological improvements and scale effects to allow for the development of competitive

new energy sources

24

(Global production)

Biomass

Hydraulic

Nuclear

Solar, wind...

1980 2000 2020(e)16% 20% 21%Share of global

energy production

Mboe/d

50

25

1980 2000 2020

2007 2009(e) 2012(e)

MWp/y**

500

100

300


Downstream

Investor Relations


European conversion marginsAdjusted net operating income (B$)

Downstream performance robust in mixed environment

Importance of ongoing productivity programs

Higher maintenance activity in refining

Marketing results maintained thanks to continuing efforts to adapt to market changes

Refining margins volatile

Strong seasonality for gasoline conversion margin ; high correlation between diesel conversion margin and oil price

* gasoline and diesel vs. heavy fuel 25

2006 2007

Environment Growth and productivity

(0.05) +0.3(0.1)

TRCV : 28.9 $/tROACE : 23%

TRCV : 32.5 $/tROACE : 21%

3.5 3.5

Inflation

Marketing (0.23) DHC +0.12

(0.15)

MaintenanceBrent

Gasoline conversion margin*

Diesel conversion margin*

Jan-06 May-06 Sept-06 Jan-07 May-07 Sept-07 Dec-07

base 100

150


Cumulative net impact of self-help plans**

Self-help supporting strong Downstream profitability

Importance of productivity plans to offset the impact of inflation and erosion of marketing marginsEstimated 90% of inflation impact to be offset by productivity gains over the period 2008-2012(e)

Concentrating refining on principal sitesSale of the 70% interest in Milford Haven refinery

* ROACE estimates based on public data for other majors** impact on net operating income, excluding contribution from Jubail, net of inflation

Strong contribution from new conversion and desulfurization projects

Downstream profitability*

26

2005 20072004 2006 2012(e)

B$

2003

New refining projects

Productivity

1.0

0.5

41.6 32.532.8 28.920.9TRCV ($/t)

ExxonMobil

Chevron

BP

RD Shell

Total

2005 20072004 20062003

30

20

10

%


HDS Lindsey

Capacity : 1.8 Mt/yStart-up 2009(e)

DHC Normandy

Capacity : 2.4 Mt/yStart-up end-2006

DHC Huelva (Cepsa)

Capacity : 2.1 Mt/yStart-up 2010(e)

HDS Leuna

Capacity : 1 Mt/yStart-up 2009(e)

Estimated payback period

Targeted investments to adapt European refining to market changes

* including share of Cepsa (48.83%)

Crude throughput* Refined products*

Increasing throughput of heavier and higher-sulphur crude and output of distillates

27

base 100

Low-sulphur40%

High-sulphur60%

2006 2012(e) 2006 2012(e)

Light products30%

Heavy products15%

Middle distillates55%

base 100

HDS Lindsey

DHC Huelva (Cepsa)

HDS Leuna

60 $/b80 $/b

DHC Normandy

years2 4 60


Port Arthur project economics

Robust economics despite cost increases thanks to the high correlation of distillate

conversion margins to crude price

Development of profitable growth projects in refining

Finalizing of FEED for Jubail refinery in Saudi Arabia

Total - Saudi Aramco partnership 400 kb/d Arab Heavy (dedicated production)Products essentially export dedicated :

55% distillates20% gasolineNo heavy products

Final investment decision in 2008Expected listing on Ryad marketStart-up 2012(e)

* including net investment in equity affiliates and non-consolidated companies, excluding turnarounds, based on 1 € = 1.50 $ for 2008(e)

Launching modernization program for Port Arthur refinery(Profitability vs Capex)

Coker (50 kb/d) + HDS (64 kb/d) + VDU (55 kb/d)Crude : Sulphur 80% 100%

Heavy 0% 50%Products : Heavy fuel : -75%

Distillates : +45%Robust economics with different supply configurationsStart-up 2011(e)

28

Refining Capex*

Development, valorization, security and others

Port Arthur

Jubail

B$

1.5

1.0

0.5

2006 2007 2008(e)

B$

2

1

60 $/b

80 $/b

Higher costsScope / Design

2008outlook

2007outlook

Hurdle rate

IRR

Capex :


Chemicals

Investor Relations


Chemicals performed well in a mixed environment

Mixed environment for Base chemicals Weakness in US petrochemicals and aromatics marginsStrong margins in Europe for the first nine months of 2007, then a pronounced squeeze in 4Q 2007 due to a sharp increase in the price of naphthaEuropean petrochemicals penalized by appreciation of the euro

Continued improvement of Specialties results

Adjusted net operating income (B$)

* results restated to exclude the contribution of Arkema before spin-off

Maintained profitability of Chemicals at 12%

European petrochemical margins and results

29

2006* 2007

Environment Growth & productivity Specialities

ROACE : 13%

ProductivityBase chemicals

1.091.16

ROACE : 12%

Base chemicals

Specialties

(0.11) +0.09+0.09

800Polymer margins

Naphtaprice

$/t

400

600

Base chemicals quarterly net operating income

200

Jan-06 May-06 Sep-06 Jan-07 May-07 Sep-07 Dec-07

M$

255

165

75

-15


Continuing to improve competitiveness of petrochemicals

Restructuring styrenics activity in Europe and partially closing CarlingConstruction of a world-class styrene unit (600 kt/y) at Normandy, start-up end-2008(e)

Optimizing gasoline pool thanks to integration of petrochemicals / refining

Research effort to produce petrochemicals base from other raw materials

Ongoing efforts to improve safety

Reducing breakeven point on naphtha-based platforms in a context of high oil prices

Pilot project for olefins conversion at Antwerp*

Pilot project « Methanolto Olefins » at Feluy

Importance of innovation

* transformation of FCC gasoline into propylene

Improving energy efficiency

(Energy consumption of main crackers)

Improving reliability

(Unreliability rate)

30

2007 2012(e)2006

base 100

50

2006 2012(e)2007

base 100 Q2

Q1Solomon

75


Investments for growth projects in petrochemicals

Estimated payback period

Progressive repositioning of petrochemicals on growth segments

Petrochemicals Capex*

* including net investment in equity affiliates and non-consolidated companies, excluding acquisitions and based on 1 € = 1.50 $ for 2008(e)** Arzew pending final agreement

Qapco (20%)

Capacity 0.7 Mt/yDebottlenecking +0,2 Mt/y

Achieved end-2007

Qatofin (49%)

Construction of 1.3 Mt/y ethane cracker

(Total 22%) and derivatives Start-up 2009(e)

Daesan (50%)

Capacity 2,7 Mt/yexpansion +30%

Achieved in 2008(e)

Arzew (51%)

1.1 Mt/y ethane cracker project and derivatives

Start-up 2013(e)

31

B$

PolyethylenePolypropylene

AsiaMiddle East

Europe & USStyrenics

Base chemicals

2006 2007 2008(e)

1.0

0.5

AlgeriaEthane**

Qatar Ethane

Daesan expansion (2007)

60 $/b

642

Daesan acquisition (2003)

years

80 $/b

0


More than 50% of petrochemicals results based on ethane or in Asia by 2015(e)

35% of capital employed in petrochemicals based on ethane or in Asia after the start-up of Arzew

Integrated projects under study in China and Saudi Arabia

Developing projects based on ethaneEthane very competitive compared to naphtha, notably in a context of high oil prices

Benefit of legacy positions in the Middle East

Targeted positions to fuel growth in Asian markets Very competitive Daesan facility in Korea

Privileged position of Middle East as export site to Asia

* in a 60 $/b Brent environment

Ethylene production capacity Petrochemicals adjusted net operating income

32

Europe

Asia

US

2015(e)20072000

Middle East Algeria

Mt/y

4

3

2

1

2015(e)*2007

Europe

Asia

US

Middle East Algeria

60 $/b 80 $/b

base100

2015(e) resultsMiddle East

Algeria


Outlook

Investor Relations


Resources*Launching major projects through 2010(e)

Operational excellence

Rapid confirmation of exploration discoveries

Leading positions on main growth segments : Africa, Middle East, LNG

Ability to create major strategic partnerships

Excellent capacity to realize new growth opportunities

Objective to put into development close to 5 billion boe of resources by end-2010

* Total’s year-end 2007 resources : proved and probable reserves plus reserves potentially recoverable from known accumulations (SPE-03/07)

JubailPort Arthur coker

Arzew cracker

Surmont Ph. II

Joslyn mining

Upgrader Canada

Ichthys LNGBrass LNG

Shtokman Ph. I

NLNG T7

Kashagan full field

CLOV

Block 32 Pole I

MTPS

Moho North

Egina

Laggan / Tormore

33

Usan Heavy oil

Deep offshore

Other liquids

LNG

Other gas

Undeveloped

Developed

> 40 years

Potential FID2008-2010(e)


Control development costs without compromising on quality

Benefit of portfolio effect on cost of Total’s drilling operations

Benefiting from portfolio effect for new developments and existing operations

Standardization of FPSOs, pooling of drilling rigs…

Optimizing developments and implementing innovative technology

Increasing recoverable reservesAccessing frontier resources

Strengthening pre-project studies and engineering Reducing risks

Adapting EPC contracts to better manage risks and upsidesPotential for significant cost reduction on major projects (Pazflor : -10%)

Promoting new contractors Emerging countriesLocal contractors

Proven track record for project management

Annual cost inflation rate by equipment*

* Total estimates for market prices

34

%

Pipe Electrical Pumps Compressors Steel

2004 2005 2006 2007

30

10

Average number of operated rigs : about 55 in 2007

2004 2005 2006 2007

Market price of deep-offshore rigs

base 100

Drilling costs : 1.7 B$ in 2007


Main 2008 investments(e)(Group share)

AkpoKashagan Mahakam Ekofisk area

Alwyn / JuraPazflor Usan

Moho Bilondo Ofon IIAngola LNG

Gonfrevillestyrenics

Port Arthur coker

Lindsey

Canadian heavy oil

Between 0.6 and 1.0 B$

Less than 0.3 B$

Between 0.3 and 0.6 B$

Substantial 2008 Capex program to fuel future growth

* including net investment in equity affiliates and non-consolidated companies, excluding acquisitions and based on 1 € = 1.50 $ for 2008(e)

Capex by segment*

Jubail

Increasing R&D budget by more than 20% to 1 B$ in 2008(e)

Anguille

75% of the increase in Capexactivity related

including increase in costs

25% related to foreign exchange

35

Upstream

Downstream

Chemicals

19 B$

16 B$

2007 2008(e)


Growth creating value thanks to capital discipline

Centralized organization and strict decision criteriaCentral scenario based on Brent at 60 $/bProfitability above cost of capital at 40 $/bSystematic review of risks and potential upsides

Upstream non-producing capital employed well-balanced between high-return projects and projects with high enrichments factors

Impact on future profitability from weight of non-producing capital employed offset by the benefit of new production

Capital employed in segments**

* cumulative cash flow over life of project divided by development Capex** at December 31

Balancing share of economic rent, benefiting local communities and managing impact on the environment

Profitability of major new projects

36

2007 2008(e)

Non-producing

Producing

2006 2010(e)

40

80

B$

Enrichment*

Deep offshore Heavy oil LNG

Deep conversion

80 $/b

60 $/b

2

IRR


Successful growth strategy supports competitive dividend policy

New production creates substantial value

Contribution from new projects and productivity programs in Downstream and Chemicals

Favoring dividend for shareholder return

* price effect based on difference between 60 $/b Brent and 2007 average Brent price (72 $/b)** based on December 31, 2007 share price

Production Contribution to net cash flow 2008(e)

Progressive sales of Sanofi

Continue to buy back shares with available cash flow

Pay-out ratio and number of shares

37

2006 2007* 2008(e)2.1

2.3

2.5

Mboe/d

80 $/b60 $/b

0.1% of Sanofi-Aventis**

1% average production growth

2 $/t refining margins

1 $/b Brent

100 200 M$0

Pay-out ratio

base 100

Number of shares

40%

30%90

2005 2006 2007


Progressively developing new axes of profitable growth

More technological content in new projects

Increasing share of gas in the energy mix

Growing need for conversion

Developing CO2 economics

Improving returns for alternative energies

Importance of nuclear as part of the supply of clean energy for the long term

Supply / demand tension and global climate change are raising the stakes

Expanding the model for sustainable growth by increasing the acceptability of our operations

Maintain our technological leadership in frontier areas

Increase our leverage to major integrated gas projects

Continue intensive R&D for clean coal and XTL and CO2 sequestration technologies

Contribute to reducing oil demand by improving the efficiency of fuels

Attain critical mass in new high-tech energies

Participate in energy arbitrage of major producing countries

Total’s strategic response for the long term

38


Disclaimer

This document may contain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations, business, strategy and plans of Total. Such statements are based on a number of assumptions that could ultimately prove inaccurate, and are subject to a number of risk factors, including currency fluctuations, the price of petroleum products, the ability to realize cost reductions and operating efficiencies without unduly disrupting business operations, environmental regulatory considerations and general economic and business conditions. Total does not assume any obligation to update publicly any forward-looking statement, whether as a result of new information, future events or otherwise. Further information on factors which could affect the company’s financial results is provided in documents filed by the Group and its affiliates with the French Autorité des Marchés Financiers and the US Securities and Exchange Commission.

Business segment information is presented in accordance with the Group internal reporting system used by the Chief operating decision maker to measure performance and allocate resources internally. Due to their particular nature or significance, certain transactions qualified as “special items” are excluded from the business segment figures. In general, special items relate to transactions that are significant, infrequent or unusual. However, in certain instances, certain transactions such as restructuring costs or assets disposals, which are not considered to be representative of normal course of business, may be qualified as special items although they may have occurred within prior years or are likely to recur within following years.

The adjusted results of the Downstream and Chemical segments are also presented according to the replacement cost method. This method is used to assess the segments’ performance and ensure the comparability of the segments’ results with those of the Group’s main competitors, notably from North America.

In the replacement cost method, which approximates the LIFO (Last-In, First-Out) method, the variation of inventory values in the income statement is determined by the average price of the period rather than the historical value. The inventory valuation effect is the difference between the results according to FIFO (First-In, First-Out) and replacement cost.

In this framework, performance measures such as adjusted operating income, adjusted net operating income and adjusted net income are defined as incomes using replacement cost, adjusted for special items and excluding Total’s equity share of the amortization of intangibles related to the Sanofi-Aventis merger. They are meant to facilitate the analysis of the financial performance and the comparison of income between periods.

Cautionary Note to U.S. Investors - The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation, such as “proved and probable reserves”, “potential reserves” and “resources”, that the SEC’s guidelines strictly prohibit us from including in filings withthe SEC. U.S. Investors are urged to consider closely the disclosure in our Form 20-F, File N° 1-10888, available from us at 2, place de la Coupole - La Défense 6 - 92078 Paris la Défense cedex - France. You can also obtain this form from the SEC by calling 1-800-SEC-0330.

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