2004 Results & Outlook Investor Relations - www.total.com February 2005 Exhibit 99.5

Strong 2004 performance Favorable environment Brent +33% to 38.3 $/b TRCV +57% to 32.8 $/t Rebound in petrochemical margins Negative impact from weaker dollar Solid operating performance Successful exploration program Hydrocarbon production +3.7% (excl. price effect) Refinery utilization rate 93% Olefin production +12% Large investment program 8.7 B€ or 10.7 B$ Record results* Adjusted net income: 9 B€ ROACE: 24% 1 * results adjusted for special items and excluding Total's equity share of amortization of goodwill and intangible assets related to the Sanofi-Aventis merger Usan Block 32 Laggan Al Khalij Peciko Sincor Upgrade Pars LNG Novatek LNG Terminals Rosa Kashagan Bonny T6 DHC China

* crude oil, source: IEA Global production capacity* Production Declining spare oil capacity creating strong tensions Concern over spare capacity and geopolitical uncertainties in 2004 Medium-term crude price linked mainly to development of new production capacity in OPEC countries and to strength of demand growth in Asia Spare capacity (OPEC) Global demand growth* Foresee medium-term Brent price above 25 $/b Maintaining a prudent 21 $/b scenario to evaluate long-term projects Rest of world Asia North America Europe 2 50 60 70 80 2002 2003 2004 Mb/d 0 1 2 3 Mb/d 2002 2003 2004 2005(e)

Refining-Petrochemicals : favorable market trends Convergence of factors supporting refining margins Higher conversion premium driven by growing demand for light products Reduction in availability of light, low-sulfur crude More stringent operating constraints: sulfur, aromatics, CO2 emissions Recent petrochemical rebound above mid-cycle Improved operating rates Favorable outlook for demand growth, mainly in Asia Annual change in European demand* Diesel Heavy fuel * source: IEA, Total estimates Global steamcracker operating rate* 3 -3 -1 1 3 % 2000-2005(e) 2005-2010(e) 85% 87% 89% 91% 2000 2002 2004 2006(e)

Results

2003 2004 % in billions of euros 4Q03 4Q04 % Record results for 4Q and full-year 2004 Operating income from business segmentsa 5.08 3.21 +58% 17.1 13.0 +32% Adjusted net incomeb 2.52 1.75 +44% 9.04 7.34 +23% Adjusted earnings per shareb (€) 4.13 2.79 +48% 14.7 11.6 +27% a adjusted for special items b adjusted for special items and excluding Total's equity share of amortization of goodwill and intangible assets related to the Sanofi-Aventis merger c dollar amounts converted from euro accounts using the average €/$ exchange rate for the period 2003 2004 % in billions of dollarsc 4Q03 4Q04 % Operating income from business segmentsa 6.59 3.82 +73% 21.3 14.7 +45% Adjusted net incomeb 3.27 2.08 +57% 11.2 8.31 +35% Adjusted earnings per shareb ($) 5.36 3.32 +62% 18.3 13.1 +40% 4

adjusted for special items Strong performance by business segments in 2004 Impact of higher oil & gas prices Production growth Higher average tax rate in 2004 Strong increase in refining margins Resilient marketing results Benefit from self-help programs Rebound in petrochemicals Negative impact of weakness in the dollar Specialties performed well Operating income Net operating income 5 Downstream +80% 4.0 2.9 2003 2004 Chemicals +114% 1.4 0.8 2003 2004 Upstream B$ 15.9 7.3 +35% 2003 2004 16 14 12 10 8 6 4 2

Profitability increased in all segments 2004 Capex in line with forecast: 8.7 B€ (10.7 B$), 71% allocated to the Upstream Impact of weaker dollar on Upstream capital employed Provisions and impairments in Chemicals for 0.9 B€ Average capital employed* (B€) Upstream Downstream Chemicals* adjusted for special items * capital employed for Chemicals excludes the contingency reserve related to Toulouse AZF (0.1 B€ at end 2004 versus 0.3 B€ at end 2003) 17.9 16.6 9.6 9.3 9.7 8.7 Profitability by segment (ROACE) 6 29% 35% 2004 2003 3.5% 8.5% 2004 2003 15% 25% 2004 2003

Total: among the best performers since 2000 Upstream: sustained production growth, low breakeven point Downstream and Chemicals: ongoing self-help programs, targeted growth and capital discipline ROACE* * adjusted results, estimates for the other majors EPS* ($) 2000 2001 2002 2003 2004 Bas 18 15 10 16 19 Haut 21 20 15 19 25 Total 20 18 15 19 24 majors Total base 2000 2001 2002 2003 2004 ChevronTexaco 100 85 55 93 151 BP 100 91 68 99 135 Shell 100 86 74 97 136 ExxonMobil 100 94 71 107 167 Total 100 97 89 131 183 Total ExxonMobil BP RD Shell ChevronTexaco % 7

2004 cash flow allocation Cash flow and investments by segment (B$) Substantial Capex program combined with the highest return to shareholders among the majors in 2004 * excludes 0.3 B€ disbursement related to Toulouse-AZF reserve and 0.2 B€ externalization of Arkema pension ** estimates of dividends paid in 2004 + share buybacks, as a % of December 31, 2003 market capitalization, calculated based on dollars 2004 return to shareholders** Dividends Share buybacks Upstream Downstream Chemicals Net cash flow Cash flow from operating activities Investments Divestments 8 13.6 7.7 5.9 2.2 4.1 1.9 1.5* 1.1 0.4 8.2% 6.8% 4.9% 5.9% 6.3% Total XOM RDS BP CVX

Dividend - Total Dividend increase: +15% to 5.40 € per share for 2004 Dividend increase expressed in dollars*: +22% Continue strong dividend increase Total's 2004 dividend pending approval at the May 17, 2005 AGM * based on €/$ 1.25 for the payment of the remaining balance of the dividend (3€ on May 24, 2005 for Total) ** 2004 pay-out: dividend declared for 2004 / 2004 adjusted EPS, estimates for the other majors Dividend - Majors 2004 Pay-out** - Majors BP ($) ExxonMobil ($) Total (€) ChevronTexaco ($) Total ($)* 9 Royal Dutch ($)* €/share +64% 2000 2001 2002 2003 2004 Total euros 100 115 124 142 164 Shell dollars 100 107 129 149 158 bp 100 107 117 127 144 xom 100 103 105 111 120 cvx 100 102 108 110 118 Total dollars 100 113 152 181 223 200 base 100 150 2000 2002 2003 2004 2001 4.10 4.70 5.40 3.80 2000 2002 2003 2004 2001 3.30 Total RD BP XOM CVX 37% 44% 39% 27% average 27%

Upstream

Benefiting fully from 2004 growth and favorable environment Technical costs* Technical costs: 8.0 $/boe + 0.7 $/boe vs. 2003 including 0.4 $/boe for exchange rate impact and price effect on volumes * consolidated subsidiaries (FAS 69) High valorization for production Context of increasing light-heavy differential Gas: +14% to 3.74 $/MBtu Valorization liquids vs. Brent Underlying growth: + 3.7% Price effect on entitlement volumes: - 1.9% 27% of production under PSC and buy-back Reported growth: + 1.8% Production 2004 Upstream ROACE: 35% Profitability recalculated based on a 25 $/b Brent environment: 21% 10 Total other majors 2001 2002 2003 2004 -4 $/b Brent -2 $/b 2000 2.3 2.5 2.8 Mboe/d + 3.7% 2003 2004 Price effect

Appraisal Bolivia Incahuasi Ipati 80% ? Kazakhstan Kairan 1 North Caspian 20.4% Angola Canela Block 32 30% ? Venus Block 31 5% Nigeria Preowei OPL 246 24% ? Congo Pegase Nord MTPS 40% ? Libya H1 - NC 186 Murzuk 24% UK 206-1-a-D Laggan 50% ? Nigeria Usan 5 OPL 222 20% ? Egina OPL 246 24% ? Angola Acacia Block 17 40% ? Congo Mobi Marine 1 Moho Bilondo 51% ? Algeria Irharen Timimoun 63.8% ? Established track record of exploration success Cumulative 2000-2004 contribution of exploration to reserve replacement potential 2004 addition: 0.9 Bboe Discovered new, very promising structures Appraisal drilling confirmed reserve potential of earlier discoveries Main 2004 successes Discoveries Share Oper. Permits Wells Principal permits taken since the start of 2004: Indonesia, United Kingdom, Norway, Algeria, Venezuela, Australia, Mauritania Share Permits Wells Oper. 11 addition during the year Bboe 1 2 3 4 5 2000 2001 2002 2003 2004

Maintain competitive reserve replacement rate Reserve replacement 2002-2004* Consolidated subsidiaries: 120 % Total Group: 106 % 2004 year-end reserves*: 11.15 Bboe Successful appraisal program and performance of producing fields in line with expectations Negative impact of approx. 270 Mboe on 2004 reserves from applying year-end prices Reserve replacement 2002-2004 excluding price effect** (based on 25 $/b) Consolidated subsidiaries : 131 % Total Group: 116 % * 2004 reserves calculated according to SEC rules (Brent = 40.47 $/b on December 31, 2004) ** reserve replacement rate for 2004, based on 25 $/b, was 107% for consolidated subsidiaries and 102% for the Group 1999-2001 2000-2002 2001-2003 2002-2004 Bas 0.63 0.7 0.6 Haut 2.45 2.22 2.63 Total 0.63 0.7 0.72 0.82 Finding costs (FAS 69) majors Total 99-01 00-02 01-03 02-04 $/boe 12

Solid and diversified portfolio of proved and probable reserves Proved and probable reserves at year-end 2004* between 500 Mboe and 1 Bboe more than 1 Bboe * limited to proved and probable reserves covered by E&P contracts on fields that have been drilled and for which technical studies have demonstrated economic development in a Brent 25 $/b environment less than 500 Mboe Reserve life close to 20 years based on current production rate 66% Oil / 34% Gas United Kingdom Norway Kazakhstan Indonesia Angola Venezuela Qatar Abu Dhabi Congo Nigeria Exploration: primary means for reserve replacement Large new gas ventures close to finalization 13

Targeted growth through 2010 of 4 % per year on average* Maintain Upstream ROACE above 20 % (Brent 25 $/b) Target rate for production growth extended through 2010 * scenario for production growth based on Brent at 25 $/b Production 2010(e) 2005-2010 growth: main projects Surmont Phase I North America Ekofisk Growth Glenelg Kristin Forvie North Snohvit Tempa Rossa Europe Trinidad Block 2c Carina Aries Yucal Placer Phase II Sincor South America Bonga BBTL Dalia / Rosa Moho Bilondo Akpo Africa CIS Peciko - Tunu Sisi/Nubi Asia Dolphin Yemen LNG Pars LNG Qatargas II Middle East oil Usan Block 17, Pole III Tyrihans Shah Deniz Kashagan gas New projects close to finalization Conventional gas Heavy oil Deep offshore Conventional oil LNG 14 Novatek Yurkharov Tarkosale East Khanchey

2011-2015: capitalize on existing base to sustain future growth Gas / LNG Deep offshore West Africa Block 17 satellites Block 32 OPL 246 OPL 222 Pegase Kashagan full field Kairan, Aktote Associated gas Sincor II Surmont full field Demonstrated expertise as operator under a variety of conditions Leverage technology and marketing to access new reserves Expansions and new giant projects Valorizing discoveries Leverage technology and integration with Downstream Ramp up major projects Pars T3 Bonny T7, T8 Angola LNG Extension Dolphin Southern Cone Novatek 15 Heavy oil Caspian Sea

40% - operator 51% - operator 24% - operator 40% - operator 40% - operator 20% - operator 20% West Africa: seven giant projects ensure future growth Rosa Moho Bilondo Akpo B17 - Pole III Dalia Usan Satellite, 150 kb/d under construction 2007(e) FPU, 75 kb/d launch in 2005 2008(e) FPSO, 175 kb/d launch in 2005 2008(e) FPSO, 240 kb/d under construction 2006(e) Development study in progress 2009-2010(e) Development study in progress 2009-2010(e) BBTL CPT, 200 kb/d under construction 2006(e) future production estimated based on Brent at 25 $/b Dalia and Rosa developments in line with forecasts Launching Moho Bilondo and Akpo developments in 2005 Preparing Usan and Block 17 Pole III for development Production - West Africa 2004 2010(e) Mboe/d 2004 base 7 major projects others 0.5 1 Total: largest international producer in Africa 16

Largest independent gas producer in Russia Young assets, operated according to international standards Projected to double production by 2010 Valorization based on domestic gas price 3 giant fields representing about 4 Bboe of proved and probable reserves Project to acquire 25% of capital Approx. 0.9 B$, or 0.8 $/boe Participation in management and operations Exploration upside Russia: acquiring a stake in Novatek Western Siberia: Largest gas province in the world 2004 Novatek production* = 435 kboe/d project pending approval from Russian anti-trust authorities * source Novatek Yamalo-Nenets Producing since 2001 Khanchey Producing since1998 Tarkosale East Tambey Upside to evaluate Producing since 2002 Yurkharov 17

Second-largest international producer in the region Demonstrated technological expertise (North Field, South Pars 2&3) Long-time player in Middle East LNG (Qatargas, Adgas, Oman LNG) Access to new large reserves 4 giant gas projects with 20-30 year production plateaus Middle East: outstanding portfolio of large, long-term gas projects future production estimated based on Brent at 25 $/b * share before entry of potential partners (LNG buyers) 0,8 2004 2010(e) liquids gas Saudi Arabia Iraq Syria Iran Oman UAE Yemen Presence of Total Participation of Total being finalized Qatargas II Yemen LNG (42.9%)* 2 trains, 3.3 Mt/y each Operator Launch project in 2005(e) 2 trains, 5 Mt/y each Engineering underway Pars LNG (30%)* South Pars 11 (60%)* Offshore gas: 2 Bcfd Operator Engineering underway Dolphin (24.5%) Qatar / UAE: 2 Bcfd Under construction Development in line with forecast Start up year-end 2006(e) 18 Kuwait Qatar Middle East production

Mt/y 5 10 15 2004 2010(e) LNG: growth of more than 10% per year on average through 2010 LNG production growth of 7% in 2004 Well balanced between plant expansions and new projects Nearly 40% of Total's gas production dedicated to LNG by 2010 Preparing several projects for 2011-2015 Pars T3, Bonny T7 & T8, Angola LNG * Total share, excluding trading ** close to finalization LNG sales* Strengthening Group's long-term production base 19 Bontang (8 trains) Qatargas (3 trains) Bonny (3 trains) Oman (2 trains) Adgas (1 train) Pars T1 & 2** 2010(e) Qatargas II** 2009(e) Yemen T1 & 2 2009(e) Bonny T6 2008 Snohvit 2007 Oman T3 2006 Bonny T4 & 5 2005

Strong development of midstream gas in 2004 Four re-gas terminal projects launched* Increase sales in the US gas market from 10 Bm3 in 2003 to 15 Bm3 in 2004 European customer base** increased from 7 Bm3/y in 2003 to 13 Bm3/y in 2004 Market access: leverage for LNG production growth Available long-term LNG resources(e) Reserved re-gas capacity 5 10 15 2004 2007(e) 2010(e) 5 10 Bm3/y Mt/y 1 Bm3/y = approx. 0.1 Bcfd * Total's share of regasification capacity ** excludes long-term sales contracts for equity gas Sabine Pass 10 Bm3/y Signed Nov. 2004 Start-up 2009(e) 2.3 Bm3/y Signed Dec. 2004 Start-up 2007(e) Fos Cavaou 0.9 Bm3/y Signed March 2004 Start-up 2005(e) Hazira Altamira 1.7 Bm3/y Signed Oct. 2003 Start-up 2006(e) 20 Secured access to markets

Downstream

Downstream results sharply higher in 2004 Refining environment favorable despite weakness in the dollar Marketing resilient given the context of high product prices Contribution of self-help programs adjusted for special items * improvement in refining environment not reflected in TRCV (mainly valorization of products and cost of feedstock) Change in Downstream operating income (B€) 2004 Downstream ROACE: 25% Recalculated with TRCV at 15 $/t and €/$ at 1.25: 13% 21 2003 2004 2.0 3.2 Productivity + 0.15 TRCV sensitivity Market effect* Shipping: + 0.1 Marketing: - 0.2 environment €/$ Improved environment for refining: + 1.15 1.5 Net operating income 2.3 Operating income

Adapting the refining system to market trends Additional investments to create value Increase capacity to refine high-sulfur crude Add production capacity for naphtha and diesel: Normandy DHC Reduce energy consumption and limit CO2 emission Progressive reduction of investments required to meet new product specifications Program 60% complete at end of 2004, close to 90% complete in 2006(e) Investments in refining* Adapting to new product specs * excludes impact of capitalizing turnarounds under IFRS, approx. 1.3 €/t/year over the period 2005-2008(e) Energy efficiency Emission reduction Performance Valorization Investments raised to 5 €/t/year* on average over the period 2005-2008(e) Safety Maintenance 22 1 2 3 4 5 2001-2004 2005-2008(e) €/t/y

Competitive advantages of refining-petrochemical integration Integration reduces investment required to meet new product specifications Status of integration efforts Operational platforms: Feyzin, Antwerp, Normandy, Port Arthur Under construction: integrating Provence and Naphtachimie (operational in 2006) Additional studies underway: Feyzin, Normandy, Port Arthur propylene naphta, butane, FCC gasoline butene hydrogen aromatics steamcracker gasoline Integrated management of gasoline pool Better valorization of aromatics Supply synergies Economies of scale Refining-Petrochemicals main product flow Refining Steamcracker Aromatics Polyethylene Polypropylene Styrene 23

Marketing : low volatility and potential to increase returns Robust marketing results in a volatile Downstream environment Benefit from brand loyalty and market segmentation strategy Diversification of network revenues Regular contributions from specialties (lubes, LPG...) and overseas marketing* Ongoing self-help programs Network rationalization Reducing fixed costs 24 Capital discipline Reduction of capital employed in mature areas Targeted investments in growth areas: Caribbean, Asia and Africa Lower working capital: customer credit reduced from 27 to 23 days over 4 years Marketing capital employed at 12/31 Growth areas Mature areas * Africa-Mediterranean Rim, Caribbean and French Polynesia 50 base 100 2002 2004 2006(e) 2008(e)

Downstream : maintain best profitability among the majors * Brent = 25 $/b, TRCV = 15 $/t ; €/$ = 1.25 ; inventory at replacement cost ; Downstream ROACE calculated based on the new reference environment is equivalent to the ROACE based on the previous reference environment (TRCV=12 $/t ; €/$=1.10) Downstream ROACE Total's Downstream ROACE in reference environment* (TRCV = 15 $/t ; €/$ = 1.25) Continuing self-help programs over the period 2004-2007 Improve valorization of production and operational performance of refineries Rationalization of European network in a very competitive environment Strengthen positions in Africa and growth areas Recurring impact on operating income : +500 M€(e) per year by 2007 Increase value-creating investments without substantially changing capital employed 25 % Total majors(e) 20 15 10 5 25 2001 2002 2003 2004 15% Impact of self-help programs 13% Target 2007/2009 2004

Chemicals

Chemicals results recover in 2004 Operating income* * adjusted for special items, paints divested early 2003, created Total-Samsung JV in August 2003 ** 2004 environment very close to mid-cycle for petrochemicals Base chemicals Intermediates Specialties Chemicals ROACE rose to 8.5% in 2004** (10% excluding Arkema) Base chemicals increased sharply Steamcracker margins rebounded in Europe and US in second half 2004 Strong performance by Total-Samsung JV in South Korea Intermediates affected by decline in dollar Specialties improved across all activities in 2004 1H00 2H00 1H01 2H04 2H01 1H03 2H03 1H04 1H02 2H02 26

Atlantic petrochemical indicator* Total's olefin production growing as margins rebound Continue to grow olefin production through 2008 Ramp up production, debottleneck and expand capacity (Port Arthur, QAPCO, Samsung JV) Objective to increase utilization rate of crackers Difficult situation for European polyethylene market Concentrating investments for expansion in Asia and Middle East 1T02 2T02 3T02 4T02 1T03 2T03 3T03 4T03 1T04 2T04 3T04 4T04 GI Atlantique 371 464 515 456 434 582 444 458 501 492 541 710 mid cycle1,1 540 540 540 540 540 540 540 540 540 540 540 540 mid cycle 1,25 550 550 550 550 550 550 550 550 550 550 550 550 2002 451 451 451 451 2003 480 480 480 480 2004 561 561 561 561 561 Total's olefin production mid-cycle €/$ = 1.25 $/t Asia / Middle East Capital employed in petrochemicals at 01/01 2004 2009(e) Europe / US 2002 2004 2003 800 600 400 * Atlantic petrochemical indicator = 50% Europe + 50% US 27 2.5 5 Mt 2008(e) 2002 2003 2004

Specialties : profitable growth and capital efficiency Sales growth of 5% in 2004 Operating income increased by 14% despite decline in dollar 2004 ROACE above 10% Strong cash flow generation Strategy for profitable growth Substantial R&D effort Expanding in growth areas, notably Asia Cash flow from Specialties Strong creation of value Cash flow from operations Investments Capital employed at 12/31* * excluding paints, divested early 2003 28 0.5 1 1.5 Cumul 2002-2004 B€ 1 2 3 2002 2003 2004 B€

Arkema: 2006 target for spin-off confirmed* Breakeven at mid-cycle Increased volumes while maintaining margins Difficult to pass on higher costs * subject to market conditions and after informing / consulting with labor representatives Restructuring to breakeven at the bottom of the cycle Debottlenecking and starting up new units Objective to restore margins Activities showed recovery starting in late 2004 despite weakness in the dollar Feb. 2004 Planned spin-off announced June 2004 Management put in place Oct. 2004 Arkema created 2005 : Preparing for spin-off Fine tune organization and systems Continue self-help programs Prepare market operation Vinyl products Industrial chemicals Performance products Mixed 2004 results 2005 Outlook 29

Maintaining ambitious profitability target Petrochemicals Arkema Petrochemicals Specialties Specialties Chemicals - capital employed Chemicals ROACE in reference environment ** Self-help programs * at 12/31/2004 ** Brent = 25 $/b ; TRCV = 15 $/t ; €/$ = 1.25 ; mid-cycle for petrochemicals Continuing to improve performance, control capital employed and rebalance portfolio Change in portfolio 30 2004* 2007/2009 5 10 2003 Target 2007/2009 7% 12% 2004 8.5% %

Outlook

2005 investment program provides for strong development * Capex based on €/$ = 1.25 versus €/$ = 1.10 in the previous reference environment Continue development of major projects: Kashagan, Dolphin, Dalia, Snohvit, Ekofisk Growth, Tunu... Pending acquisition: 25% of Novatek (~0.9 B$) Upstream: priority to growth 2006-2009(e) Capex: 10 to 11 B$ per year In-line with earlier estimates Takes into account new €/$* assumption and capitalization of turnaround costs under IFRS 2005 Capex budget: 12 B$ Refining: peak year for DHC project plus impact of IFRS on capitalizing turnarounds Marketing: developing new positions Downstream: peak in Capex Chemicals: investment discipline 31 70% 20% 10%

Cash flow allocation policy Average annual available cash flow 2005-2009(e) * based on €/$ = 1.25 and excluding sales of Sanofi-Aventis shares Brent ($/b) and TRCV ($/t) Investments Cash flow available before dividend* Large investment program Net-debt-to-equity ratio around 25-30% under IFRS Sales of Sanofi-Aventis shares not planned for the short term (valued at 10B€ at beginning of 2005) Cash flow after Capex and dividend available for share buyback 32 In 2004, pay-out ratio for Total above the average of the majors Maintain target pay-out ratio of 50% for the medium term 16 12 25 15 30 30 B$ 20 8 4 20 15

Continuity of growth strategy well adapted to changing environment 2005-2006 milestones 12 new start-ups: 300 kboe/d (net) at plateau Launch development of giant projects to sustain long-term growth (West Africa, LNG...) Exploration in more than 25 countries Novatek Start up DHC at the Normandy refinery Rationalize European network Develop marketing in Africa and Asia Increase olefin production Grow in Asia Spin-off Arkema in 2006* Strong positions in high-growth areas and top-quartile profitability Upstream Strengthening leadership positions in Europe and Africa plus selective growth Rebalancing portfolio Downstream Chemicals 33 * subject to market conditions Continuing to combine growth and profitability at the highest level

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. 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 & probable reserves, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosure in our Form 20F, File N° 1-10888, available from us at 2, place de la Coupole - La Defense 6 - 92078 Paris la Defense cedex - France. You can also obtain this form from the SEC by calling 1- 800-SEC-0330. Disclaimer 34