Exhibit 99.3

2004 Mid-Year Review Investor Relations - www.total.com September 2004

Results

Change 1H03 1H04 B&128; 1H03 1H04 Change B$ Strong increase in first half 2004 results 1 dollar amounts converted from euro accounts using the average exchange rate for the period * adjusted for special items 7.57 6.86 +10% Operating income from business segments* 9.29 7.58 +23% 4.04 3.77 +7% Net operating income from business segments* 4.96 4.17 +19% 4.14 3.89 +7% Net income* 5.08 4.30 +18% 6.67 6.05 +10% Earnings per share* (&128;, $) 8.19 6.69 +22% Brent 33.7 $/b versus 28.7 $/b in 1H03 (+17%) European refining margins (TRCV) Euro-dollar parity 1.23 $/&128; versus 1.10 $/&128; in 1H03 (-11%) 28.0 $/t versus 24.9 $/t in 1H03 (+12%)

1.4 1.6 1H03 1H04 Improved performance across all business segments Operating income* (B$) High-price environment 4% production growth * adjusted for special items ROACE based on accounts in euros for the twelve months ended June 30, 2004 adjusted for special items and excluding goodwill amortization in the Chemicals segment ROACE: 31% Strong European refining margins Ongoing productivity programs Base chemicals affected by higher raw material costs Specialties performed well ROACE: 17% ROACE: 4% Upstream Downstream Chemicals 2 5.9 7.3 1H03 1H04 0.3 0.4 1H03 1H04

ROACE at the best level among the majors ROACE max min majors* ROACE adjusted for special items * ExxonMobil, BP, Shell, Total, ChevronTexaco Profitable growth Ongoing self-help programs in all segments Financial discipline Consistent investment policy Efforts to reduce working capital Total 3 12 months ended June 30, 2004 10 15 20 2000 2001 2002 2003 %

Capex and returns to shareholders at the highest level among the majors for the 2001-2003 period ratios calculated in dollars for the period 2001-2003 * excluding acquisitions Capex* (% of cash flow from operating activities) Large investment program reflecting the quality of the portfolio of projects Low breakeven points maximizing cash flow from operating activities Proceeds from sales of non-strategic assets returned to shareholders Dividends + share buybacks (% of year-end 2000 market cap.) 4 Total other majors 70% 66% 18% 12% 10% 11% 11% Total Exxon Mobil RD Shell BP Chevron Texaco

Strong EPS growth since 2001 EPS* ($) * adjusted for special items source: company reports 5 base Total ExxonMobil BP RD Shell ChevronTexaco 50 100 150 1H01 2H01 1H02 2H02 1H03 2H03 1H04

Impact of new IFRS accounting standards for Total Convergence of the new standards with US GAAP Treasury shares held as short-term investments deducted from shareholders' equity Discontinue amortization of goodwill Transition has no significant impact on net fixed assets Inventory valuation FIFO required in place of replacement cost Impact on net income and equity No significant impact on net income from IFRS, except inventory valuation 2004 IFRS financial statements available in April 2005 Results using replacement cost will also be published 6

Upstream September 2004 Investor Relations - www.total.com

Successful year-to-date 2004 exploration program Main successes 2004 activity (seismic, exploration, appraisal) Norway Blocks 6406-7 & 6406-8 (40%) New exploration licenses Laggan (50%) Discovery United Kingdom Nigeria OPL 246 (24%) Preowei and Egina OPL 222 (20%) Positive appraisal on Usan / Ukot Libya Murzuk - NC 186 (24%) New discovery Kairan New discovery on Kashagan permit Kazakhstan Indonesia North Bali (39.9%) New exploration permit Block 17 (40%) Acacia 2 Block 32 (30%) Canela 1 Block 31 (5%) Venus 1 Angola MTPS (40%) Pegase North Moho Bilondo (51%) Positive appraisal Congo 7

technical costs and reserve replacement costs: consolidated subsidiaries (FAS 69) Best technical cost and reserve replacement cost performance among the majors Controlling technical costs despite pressure from service companies Low reserve replacement costs create a competitive advantage for future profitable growth Reserve replacement costs Technical costs 8 $/boe 6 8 10 1999 2000 2001 2002 2003 Shell BP ChevronTexaco ExxonMobil Total 4 6 8 1999-2001 2000-2002 2001-2003 Shell BP ChevronTexaco ExxonMobil Total $/boe

Mature areas (OECD) Less exposed to regions with declining production Production growth for Total Growth areas (non-OECD) Largest producer among the majors Well-diversified portfolio source: company reports 1999-2003 production Production base : solid and well-positioned for the future 9 Total Exxon Mobil Chevron Texaco Shell BP 1 2 Mboe/d Total Exxon Mobil Chevron Texaco Shell BP 1 2 3 Mboe/d

Continuing production growth in 2004 Plateau Phase I: 100 Mcfd Yucal Placer (69.5%) Plateau for Girassol raised to 230 kb/d Jasmim (40%) Plateau: 40 kb/d Al Jurf (37.5%) Al Khalij North (100%) Plateau: 20 kb/d Plateau: 35 kboe/d Skirne (40%) Plateau: 180 kboe/d Kvitebjorn (5%) Plateau: 125 kb/d Amenam (30.4%) 2004 start-ups Production increase on 2003 start-ups in line with expectations Operated fields: 2004 start-ups successful Productivity on existing fields North Sea maintenance in 3Q'04, debottlenecking Sincor Upgrader in 4Q'04 Matterhorn (100%) Plateau: 40 kboe/d 2003 start-ups 10 Plateau: + 500 Mcfd Peciko 3 & 4 (50%)

Confirming 2003-2008 growth target: + 4% per year on average Mboe/d Production (SEC) + 4% per year on average* * 20 $/b Brent reference environment Decline rate on existing base limited to 3 - 4% per year on average from 2003 to 2008(e) Sustained investment program Confirming Upstream Capex at approx. 7 B$ per year on average over the 2004-2008 period Capital-efficient growth given context of increasing development costs Base New projects 11 2003 2008(e) 3 2 1

Skirne 40.0% 35 ? producing Al Khalij North 100.0% 20 ? producing Peciko 3 & 4 50.0% 90 ? producing Yucal Placer Phase I 69.5% 20 ? producing Kvitebjorn 5.0% 180 ? Bonga 12.5% 225 ? Ekofisk area growth 39.9% 100 ? Glenelg 49.5% 25 ? ? Trinidad Block 2C 30.0% 80 ? Carina / Aries 37.5% 30 ? ? BBTL 20.0% 200 ? Dalia 40.0% 240 ? ? Kristin 6.0% 240 ? Forvie North 100.0% 20 ? ? Snohvit LNG 18.4% 120 ? Shah Deniz 10.0% 190 ? Surmont Phase I 43.5% 30 ? Rosa 40.0% 150 ? ? Dolphin 24.5% 370 ? Yucal Placer Phase II 69.5% 40 ? Akpo 24.0% 175 ? Moho Bilondo 51.0% 75 ? Kashagan Phase I 20.4% 450 ? Tempa Rossa 50.0% 50 ? 2004-2008 growth secured by defined and diversified projects * 20 $/b Brent reference environment ** pending finalization of agreements 2004 2005(e) 2006(e) 2007(e) 2008(e) ** 12 Production (SEC) Operated Development launched Target peak 100% (kboe/d) Share Main projects Start-up Mboe/d + 4% per year on average* Base New projects 2003 2008(e) 3 2 1

Exploration New ventures More value from the existing base Large, long-term projects Several projects in negotiation or under evaluation (Middle East, South America, Africa, Russia-CIS) Productivity on mature fields Ekofisk Cameroon Gabon Launched development of giant fields Kashagan Phase I Dolphin Surmont Phase I Exploration success West Africa Kazakhstan North Sea North Africa 13 2009-2013 growth: highlights from past 12 months Many discoveries to valorize Pre-development studies Usan/Ukot 3rd pole Block 17 Launched LNG projects Bonny T6 Launched satellite developments Rosa Sisi-Nubi / Tambora Great Mabruk

West Africa: successful exploration sustains long-term growth Post-2008 growth potential provided by many discoveries Most fields operated by Total West Africa production Discoveries developed Girassol, Jasmim Kuito Amenam, EA Dalia, Rosa Bonga BBTL Discoveries being developed Moho Bilondo (Congo) Pegase (Congo) Akpo, Preowei (OPL 246) Usan/Ukot (OPL 222) Lirio, Cravo (Block 17) Perpetua, Acacia (3rd pole Block 17) Gindungo, Canela (Block 32) Discoveries to be developed future production based on 20 $/b Brent reference environment 14 Discoveries put into production since 1999 1999 base 1.0 0.5 Mboe/d 1999 2003 2008(e) 2013

Caspian Sea Kairan Kashagan Aktote Kalamkas Next generation of large projects fueling long-term production Success at Sincor Reservoir engineering Upgrader technology Positive Surmont pilot (SAGD) Recovery rate upside Athabasca Surmont I and II (200 kb/d*) Venezuela Sincor II negotiations Tempa Rossa Integrated project Qatar-U.A.E.: Dolphin (2 Bcfd*) LNG projects in negotiation Exploration Saudi Arabia Heavy oil Kashagan production build up over 10 years to more than 1 Mboe/d* New structures discovered Kalamkas, Kairan, Aktote Valorizing associated gas Capitalize on existing positions and technological innovations to gain access to new reserves Strong historical presence 2nd largest international producer (441 kboe/d in 2003) Participating in 3 LNG plants Petrochemicals and power generation Khuf gas, LNG expertise 15 * 100% •

2 4 6 8 10 2013 2008(e) 2003 2 4 6 8 10 Exxon Mobil BP Total Chevron Texaco Shell ENI BG LNG: strengthening positions over the long term * 100% plant capacity at end 2003 ** Total Group share, excludes trading LNG sales 2003(e) Mt/y + 8%/year on average LNG sales** Mt/y Qatargas (debottlenecking) 2004-2006 Bonny T4 & T5 2005 Snohvit 2006 Bonny T6 2007 Bontang: increasing volumes Current developments Angola LNG Basic engineering Pars LNG Shareholder agreement Qatargas II Negotiations underway Yemen LNG Marketing Bonny T7 Under study Post-2008 growth Several projects currently in negotiation or under study to secure long-term growth 2013 2008(e) 2003 Medium-term growth sustained by expansion of existing plants Bontang 22.2 Mt/y Bonny T1, T2 & T3 9.0 Mt/y Qatargas 8.2 Mt/y Adgas 5.6 Mt/y Oman LNG 7.1 Mt/y Participation in nearly 40% of worldwide LNG capacity* 16

Marketing LNG: accessing new markets Long-term commercial resources Access to markets secured Rapid growth in the Atlantic Basin Participating in new re-gas projects in Mexico and France New long-term commercial resources: Bonny, Snohvit Strengthening access to Asian markets Participating in the Hazira re-gas project in India Continuing negotiations to increase access to new markets * pending approval Highlights past 12 months Altamira 1.7 Bm3/y Fos II 2.0 Bm3/y* Bonny 1.5 Bm3/y Snovhit 1.0 Bm3/y Hazira 0.9 Bm3/y 17

Downstream

European refining margins (TRCV) $/t 50 30 10 40 20 European Downstream environment: tight markets Marketing margins in Europe (OPAL)* 8.0 20.9 29.4 94 100 94 &128;/m3 150 100 50 2003 2002 2004 2003 2002 2004 125 75 Strong European refining margins, driven by US gasoline demand and low inventory levels in the Atlantic Basin Marketing margins squeezed by increasing refined product prices 1994-2003 average 01/01/2000 01/02/2000 01/03/2000 01/04/2000 01/05/2000 01/06/2000 01/07/2000 01/08/2000 01/09/2000 01/10/2000 01/11/2000 01/12/2000 01/01/2001 01/02/2001 01/03/2001 01/04/2001 01/05/2001 01/06/2001 01/07/2001 01/08/2001 01/09/2001 01/10/2001 01/11/2001 01/12/2001 01/01/2002 01/02/2002 01/03/2002 01/04/2002 01/05/2002 01/06/2002 01/07/2002 01/08/2002 01/09/2002 01/10/2002 01/11/2002 01/12/2002 01/01/2003 01/02/2003 01/03/2003 01/04/2003 01/05/2003 01/06/2003 01/07/2003 01/08/2003 01/09/2003 01/10/2003 01/11/2003 01/12/2003 01/01/2004 01/02/2004 01/03/2004 01/04/2004 01/05/2004 01/06/2004 01/07/2004 01/08/2004 Est 12.6 6.5 23.7 37.1 12.6 18.4 25.5 21.1 34.3 43 20 30 10.9 12 22.5 28.9 18.9 8.4 11.4 9.3 18 23.6 12.3 8.3 5.5 1.2 0.4 2.5 4.9 7.2 6 6.8 13.1 16.6 19.4 12.4 15.5 34.1 47.4 25.8 14.7 12.5 14.1 15.1 14.7 16.6 22.2 18.1 21.5 20.5 22.8 35.6 35.5 32.2 38 27.2 Moyenne 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 8 8 8 8 8 8 8 8 8 8 8 8 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 20.9 29.4 29.4 29.4 29.4 29.4 29.4 29.4 29.4 Echelle 42 42 42 42 0 0 0 0 0 Echelle 32 32 32 32 10 10 10 10 10 Echelle 22 22 22 22 15.4 15.4 20 20 20 12 12 12 12 30 30 30 30 30 2 2 2 2 40 40 40 40 40 20.9 20.9 50 50 50 50 50 * weighted to reflect portfolio of Total 01/01/2000 01/02/2000 01/03/2000 01/04/2000 01/05/2000 01/06/2000 01/07/2000 01/08/2000 01/09/2000 01/10/2000 01/11/2000 01/12/2000 01/01/2001 01/02/2001 01/03/2001 01/04/2001 01/05/2001 01/06/2001 01/07/2001 01/08/2001 01/09/2001 01/10/2001 01/11/2001 01/12/2001 01/01/2002 01/02/2002 01/03/2002 01/04/2002 01/05/2002 01/06/2002 01/07/2002 01/08/2002 01/09/2002 01/10/2002 01/11/2002 01/12/2002 01/01/2003 01/02/2003 01/03/2003 01/04/2003 01/05/2003 01/06/2003 01/07/2003 01/08/2003 01/09/2003 01/10/2003 01/11/2003 01/12/2003 01/01/2004 01/02/2004 01/03/2004 01/04/2004 01/05/2004 01/06/2004 01/07/2004 01/08/2004 Est 12.6 6.5 23.7 37.1 12.6 18.4 25.5 21.1 34.3 43 20 30 10.9 12 22.5 28.9 18.9 8.4 11.4 9.3 18 23.6 12.3 8.3 91 94 84 95 99 97 92 89 89 96 105 92 97 88 110 120 109 97 93 90 107 96 98 101 91 100 90 91 90 110 87 94 Moyenne 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 94 94 94 94 94 94 94 94 94 94 94 94 100 100 100 100 100 100 100 100 100 100 100 100 94 94 94 94 94 94 94 94 Echelle 42 42 42 42 0 0 92 92 Echelle 32 32 32 32 10 10 94 94 Echelle 22 22 22 22 15.4 15.4 100 100 12 12 12 12 30 30 125 125 2 2 2 2 40 40 150 150 20.9 20.9 50 50 18

Donges Leuna Refining: capitalizing on scale and asset integration European refining well balanced thanks to growing international trade Tightness in US gasoline market sustaining CIF value in the Atlantic Basin Growing domestic market demand for distillates satisfied by increased imports from the CIS Competitive position for Total, largest refiner in W. Europe with about 20% of capacity Coastal refineries Hub management system Large charter capacity secured in tight shipping market Net gasoline exports: 18 Mt in 2003 (approx. 15% of W. European production) Flow of refined products Net distillates imports: 22 Mt in 2003 (nearly 10% of W. European demand) * Cepsa Immingham Milford Haven Normandy Rome Flanders Grandpuits Feyzin Provence Huelva* Algesiras* Antwerp Vlissingen 19

Adapting refining system to market trends Investing to adapt refinery output to changes in demand Gasoline: Managing the surplus maximize value from exports to the US flexibility to use as feedstock in steamcrackers Diesel: Large production increase in 2006 after start-up of DHC in Normandy Heavy fuels: Reducing excess (DHC impact) Complying with 2009 product specifications 9 out of 12 refineries capable of producing 10 ppm sulfur gasoline and diesel by 2005 Improving energy efficiency of the refineries Need for gasoline imports in the US* * estimates based on IEA/DOE projections Shortfall of diesel production in Europe* Total other refiners 20 20 40 60 Mt/year 2003 2008(e) -30 -20 -10 2003 2008(e) 2003 2008(e) Mt/year

25 50 75 100 2002 2004(e) 2006(e) 2008(e) base kt/y 1 2 2000 2001 2002 2003 Strengthening European network Seeking critical mass in selected markets (at least 10% market share) Rebranding of TOTAL stations in Europe nearly 95% complete (6,700 stations) Market segmentation strategy in France TOTAL network augmented by 300 low price Elf brand stations and 2,200 rural Elan stations Adapting the network Investing in high-potential stations Closing approx. 800 marginal stations by end 2008 Increasing non-fuel sales Developing niche markets AS24 network: 560 stations dedicated to heavy trucks in 12 European countries Capital employed in European network Throughput per station 21

Capex budget of 1.5 B&128; per year on average over the 2004-2006(e) period Investments with attractive returns 2004-2006 productivity plans: + 400 M&128;(e) recurring annual benefit to operating income by 2006 Improve performance of the refining system Control fixed costs Integrate refining and petrochemicals more closely Strengthen the European network Selective growth Specialties (LPG, lubricants, special fluids) Strengthen positions in Africa and along the Mediterranean Rim Asia: grow the networks in Pakistan and Philippines Continuing to improve Downstream performance * TRCV = 12 $/t ; &128;/$ = 1.1 ; Brent = 20 $/b ROACE reported recalculated using reference environment* 22 10 15 20 2000 2001 2002 2003 %

Chemicals

Mixed first half 2004 results for Chemicals Operating income* (B&128;) Base chemicals and polymers Intermediates and performance polymers Specialties Base chemicals affected by higher raw material costs Good results from the Samsung-Atofina JV Negative impacts from the weak dollar and high raw material costs All sectors delivered better performance * adjusted for special items 23 0.21 0.25 1H03 1H04 0.03 0.05 1H03 1H04 0.10 0.08 1H03 1H04

Petrochemicals: productivity efforts and targeted growth Capital employed end 2003: 3.9 B&128;* Europe United States Rest of world PP Base chemicals PE Styrenics Improve structure and performance of system Reduce downtime Reduce steamcracker breakeven by improving energy efficiency and controlling fixed costs Continue to optimize European plants Further integrate with refining Expand in high-potential markets Developments in Qatar and expansion of Samsung-Atofina platform in South Korea High value specialty products Current situation Increasing capacity utilization rates Difficult to pass on higher naphtha costs in Europe Market conditions improving more in Asia than on other continents Demand for aromatics growing faster than for olefins * excluding chlorochemicals 24

Specialties: continue to pursue growth strategy Operating income* Hutchinson: continued growth supported by sustained R&D programs and technological leadership Resins: consolidation in mature markets Adhesives: growth driven by well-known brand names Atotech: strong growth thanks to successful repositioning in Asia 1H04 Sales: 3 B&128; Hutchinson Adhesives Resins Atotech * excluding paints business divested in 2003 25 0.2 0.4 0.6 2001 2002 2003 1H04 annualized B&128;

Creation of CIP entity well advanced Management named mid-2004 Completed information and consultation process with labor representatives Unveiled new organization More than 40 countries, 70 plants Employees involved: 19,000 Initiated process to transfer assets Approx. 150 subsidiaries Initial legal entities formed in October 2004 Expect to complete operation in 2006* * depending on market conditions and after informing / consulting with labor representatives 2003 pro forma sales: 5 B&128; Intermediates Performance products Chlorochemicals End 2003 employees Intermediates Performance products Chlorochemicals 26

Outlook

Strategy suited to different oil price scenarios Sustained high price (30 $/b) Strong cash flow generation Pressure on technical costs Increased competition Facilitates capital intensive projects Reversion to 1990s average price (approx. 20 $/b) Upstream earnings resilient to decrease in oil price Portfolio of low-breakeven projects Ability to invest for long-term growth Uncertainties on fundamentals Longevity of Asian demand growth Increase in OPEC production capacity Production decline rates in OECD countries Oil price scenarios Recent surge in Brent price 01/01/1990 01/02/1990 01/03/1990 01/04/1990 01/05/1990 01/06/1990 01/07/1990 01/08/1990 01/09/1990 01/10/1990 01/11/1990 01/12/1990 01/01/1991 01/02/1991 01/03/1991 01/04/1991 01/05/1991 01/06/1991 01/07/1991 01/08/1991 01/09/1991 01/10/1991 01/11/1991 01/12/1991 01/01/1992 01/02/1992 01/03/1992 01/04/1992 01/05/1992 01/06/1992 01/07/1992 01/08/1992 01/09/1992 01/10/1992 01/11/1992 01/12/1992 01/01/1993 01/02/1993 01/03/1993 01/04/1993 01/05/1993 01/06/1993 01/07/1993 01/08/1993 01/09/1993 01/10/1993 01/11/1993 01/12/1993 01/01/1994 01/02/1994 01/03/1994 01/04/1994 01/05/1994 01/06/1994 01/07/1994 01/08/1994 01/09/1994 01/10/1994 01/11/1994 01/12/1994 01/01/1995 01/02/1995 01/03/1995 01/04/1995 01/05/1995 01/06/1995 01/07/1995 01/08/1995 01/09/1995 01/10/1995 01/11/1995 01/12/1995 01/01/19 96 01/02/1996 01/03/1996 01/04/1996 01/05/1996 01/06/1996 01/07/1996 01/08/1996 01/09/1996 01/10/1996 01/11/1996 01/12/1996 01/01/1997 01/02/1997 01/03/1997 01/04/1997 01/05/1997 01/06/1997 01/07/1997 01/08/1997 01/09/1997 01/10/1997 01/11/1997 01/12/1997 01/01/1998 01/02/1998 01/03/1998 Brent 21.12 19.69 18.3 16.49 16.31 15.05 17.48 27.99 34.55 34.25 33.15 28.25 23.99 19.46 19.04 19.14 19.08 18.15 19.09 19.75 20.48 22.19 21.09 18.33 18.18 18.15 17.65 19.05 19.88 21.09 20.24 19.76 20.2 20.3 19.14 18.1 17.34 18.45 18.74 18.64 18.51 17.63 16.79 16.68 15.99 16.59 15.12 13.51 14.14 13.88 13.88 15.06 16.18 16.79 17.54 16.72 15.81 16.43 17.23 15.79 16.54 17.08 17.06 18.58 18.49 17.38 15.9 16.02 16.69 16.1 16.77 17.95 18.09 17.87 19.87 20.95 19.2 18.36 19.63 20.44 22.53 24.41 22.79 23.93 23.59 21.24 19.15 17.48 18.98 17.61 18.47 18.72 18.32 19.92 19.24 17.25 15.21 14.04 13.03 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 $/b 90 92 94 96 98 00 02 04 average since 2000 90s average 27

Sustained Capex level over the 2004-2008 period Controlled increase in Capex close to 10 B$ per year on average over the 2004-2008(e) period Investment criteria Base case economics at 21 $/b Brent Test resilience of large projects at 17 $/b Brent Assess upside at 25 $/b Brent Downstream Upstream Chemicals CAPEX by segment 5 10 average 1999-2003 average 2004-2008(e) B$ 28

Upstream Chemicals Accelerate shift in capital employed to Upstream through 2008 capital employed at beginning of year 25% 27% 48% 25% 25% 50% 18% 22% 60% 2002 2005(e) 2008(e) Amont Aval Chimie Est 50 25 25 Amont Aval Chimie Est 60 22 18 Amont Aval Chimie Est 48 25 27 29

Combining growth and returns to shareholders * corresponds to 21.5% of voting rights Hydrocarbon production Dividends ($) Priority to high-return investments (mainly organic growth) Dynamic dividend policy: target pay-out ratio of 50% and semi-annual payments First interim dividend payment: November 24, 2004 Net cash flow after investments and dividends available for share buybacks 13%* stake in Sanofi-Aventis Potential valuation above 10 B&128; thanks to merger benefits and outlook for growth 30 1999 2000 2001 2002 2003 ChevronTexaco RD Shell ExxonMobil Total BP 100 150 200 250 base 90 100 110 120 130 1999 2000 2001 2002 2003 ChevronTexaco Shell ExxonMobil Total BP base

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. The financial information contained in this document has been prepared in accordance with French GAAP, and certain elements would differ materially upon reconciliation to US GAAP. 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 Autorite des Marches Financiers and the US Securities and Exchange Commission. The 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 monitored at the Group level and 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. Performance measures excluding special items such as operating income, net operating income and net income adjusted for special items, are meant to facilitate the analysis of the financial performance and the comparison of income between periods. Disclaimer