TOTAL S.A. HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

November 5, 2010                

Mr. H. Roger Schwall

Assistant Director

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

By EDGAR, “CORRESP” Designation

          Re: Total S.A. Form 20-F for the Fiscal Year Ended December 31, 2009 Filed April 1, 2010 File No. 1-10888

Dear Mr. Schwall:

Thank you for your letter dated September 28, 2010, setting forth the Staff’s comments relating to our Annual Report on Form 20-F for the year ended December 31, 2009 filed on April 1, 2010 (the “2009 Annual Report”). Set forth below is the response of TOTAL S.A. (the “Company”) to the Staff’s comments.

To facilitate the Staff’s review, we have included in this letter the captions and comments from the Staff’s comment letter in bold text and have provided the Company’s response immediately following each comment.

As requested, we acknowledge that: (i) the Company is responsible for the adequacy and accuracy of the disclosure in the filing; (ii) Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and (iii) the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

[*** CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION]

Mr. H. Roger Schwall Securities and Exchange Commission Page 2

General

1. In light of recent events in the Gulf of Mexico, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability in the event that your employees or equipment are involved in an event that leads to property damage, personal injury, death, or discharge of hazardous materials into the environment. For example, and without limitation, please address the following:

• Disclose your insurance coverage with respect to any liability related to any such event. Such disclosure should address the types of claims covered and the applicable policy limits and deductibles. For example, and without limitation, you should expand your disclosure regarding your insurance coverage for potential environmental liabilities. Also disclose whether your existing insurance would cover any claims made against you by or on behalf of individuals who are not your employees in the event of personal injury or death, and whether your customers or partners would be obligated to indemnify you against any such claims. In addition, discuss the effects of such an event in light of your ownership of Omnium Insurance and Reinsurance Company.

• Disclose the material terms of your related indemnification obligations and those of your customers and partners in the case of any event described above.

Such disclosure should be set forth in both Item 3.D and Item 4 of your Form 20-F. Please provide a sample of your proposed disclosure for our review. In responding to this comment, please consider all your products and services, not just those involved in offshore operations.

R: We have reviewed our disclosure in light of recent events in the Gulf of Mexico and believe that we have disclosed all material information regarding our potential liability in the event that our employees or equipment are involved in an event that leads to personal injury, death, property damage or discharge of hazardous materials into the environment.

In this connection, we respectfully draw the Staff’s attention to the disclosure on pages 5-6 of our 2009 Annual Report (Item 3 – Risk Factors), where we state that “we are exposed to risks regarding safety and security of our operations” and that “[o]ur workforce and the public are exposed to risks inherent to our operations that potentially could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.” These risks are further detailed on page 51 of our 2009 Annual Report (Item 4 – Other Matters – Industrial and environmental considerations), where we state that “the broad scope of TOTAL’s activities, which include drilling, oil and gas production, on-site processing, transportation, refining and petrochemical

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activities, storage and distribution of petroleum products, and production of base chemical and specialty products, involve a wide range of operational risks”. In this same section we further specify that these operational risks include explosion, fire or leakage of toxic products, as well as environmental risks related to emissions into the air, water or soil and the creation of waste. In the transportation area, we specify that the type of risk depends not only on the hazardous nature of the products transported, but also on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road), the volumes involved, and the sensitivity of the regions through which the transport passes (population density, environmental considerations). We also provide a further breakdown of the risks we face by division or sector of activity. For example, with respect to Exploration & Production, we state that we face risks related to the physical characteristics of an oil or gas field. These include eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks generating toxic risks and risks of fire or explosion. As further stated on pages 51-52 of our 2009 Annual Report, “all these events could possibly cause injury or even death, damage or even destroy crude oil or natural gas wells as well as related equipment and other property, lead to a disruption of activity or cause environmental damage. In addition, since exploration and production activities may take place on sites that are ecologically sensitive (tropical forest, marine environment, etc.), each site requires a risk-based approach to avoid or minimize the impact on human health, the related ecosystem and biodiversity.” We also identify specific risks related to our activities in the Chemicals segment and the Refining and Marketing division.

In light of these risks, we maintain worldwide third-party liability insurance coverage for all of our subsidiaries. We describe our insurance and risk management policies on pages 60-61 of our 2009 Annual Report. The amount of our third party liability insurance is consistent with industry practice though the extent of our coverage in any given year may vary depending on conditions in the insurance market. In 2009, our third-party liability insurance for any liability (including potential environmental liabilities) was capped at $800 million. Deductibles for third-party liabilities fluctuate between €0.2 million and €1.0 million depending on the nature of the liability, and are borne by the relevant subsidiary. In response to the Staff’s comment, we can confirm that this insurance coverage would cover any claims made against us by or on behalf of individuals who are not our employees in the event of personal injury or death.

In addition to third-party liability insurance, we also maintain insurance to cover us against the risk of damage to Group property and/or business disruption. As described in further detail on page 61 of our 2009 Annual Report, our property damage and business disruption insurance varies by sector and by site and is based on the estimated cost of reconstruction under maximum loss scenarios. For example, with respect to the highest estimated risks of the Group (floating production, storage and offloading units (FPSO) in Angola and in the case of our main European refineries), we maintained coverage in 2009 in the amount of close to $1.5 billion. Deductibles for property damage fluctuate

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between €0.1 million and €10 million depending on the level of risk, and are borne by the relevant subsidiary. For business interruption, coverage begins sixty days after the event giving rise to the interruption.

As stated on page 60 of our 2009 Annual Report, we have our own insurance and reinsurance company, Omnium Insurance and Reinsurance Company (OIRC). OIRC is integrated into the Group’s insurance management and is used as a centralized global operations tool for covering the Group’s risks. OIRC provides our subsidiaries with third-party liability insurance as well as coverage for property damage and, for our main refining and petrochemical sites, business interruption, and negotiates a reinsurance program at the Group level with mutual insurance companies for the oil industry and commercial reinsurers. In 2009, the net amount of risk retained by OIRC after reinsurance was a maximum of €50 million per third-party liability insurance claim and €50 million per property damage and/or business interruption insurance claim. Accordingly, in the event of any loss giving rise to an insurable claim, the effect on OIRC would be limited to its maximum retention of €50 million per event, as described above, and would not jeopardize OIRC in light of its financial strength.

While we believe our insurance coverage is in line with industry practice and sufficient to cover normal risks in our operations, we are not insured against all possible risks. In the event of a major environmental disaster, for example, it is possible that our liability may exceed the maximum coverage provided by our third-party liability insurance. The loss we could suffer in the event of such a disaster would depend on all the facts and circumstances and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, including economic damage not immediately connected to the disaster. As stated on page 61 of the 2009 Annual Report, “[t]he Group cannot guarantee that it will not suffer any uninsured loss” and there can be no assurance, particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Group.

If an event occurs leading to personal injury, death, property damage or discharge of hazardous materials into the environment, contractual terms may provide for indemnification obligations, either by us in favor of third-parties or by third-parties for our benefit. With respect to joint ventures operated by us, contractual terms generally provide that we assume liability for damages caused by our gross negligence or willful misconduct. With respect to joint ventures in which we have an interest but that are operated by others, contractual terms generally provide that the operator assumes liability for damages caused by its gross negligence or willful misconduct. All other liabilities of any type of joint venture are generally assumed by the partners in proportion to their respective ownership interests. With respect to third party providers of goods and services, the amount and nature of liabilities assumed by the third party depends on the

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context and may be limited by contract. With respect to our customers, our products meet applicable specifications and we abide by all applicable consumer protection laws.

While the 2009 Annual Report already includes substantially all of the information summarized in the response to this Staff comment (as well as further detail on TOTAL’s insurance and risk management), consistent with our historical approach to risk factor disclosure, a portion of the information was included in Item 4 under the headings “Other Matters – Industrial and environmental considerations” and “Other Matters – Insurance and risk management”. We have taken this approach to risk factor disclosure in order to minimize differences in presentation between our Annual Report on Form 20-F and the annual report we prepare in France. In order to draw attention to the additional disclosure, our practice in the Annual Report on Form 20-F has been to include a cross-reference to the relevant section of Item 4 in the introduction to our Risk Factors in Item 3. In order to address the Staff’s concern that this disclosure be presented both in Item 3.D and in Item 4 of the Form 20-F, we would propose to add a risk factor to our next Annual Report on Form 20-F substantially along the lines of the response to this Staff comment.

2. In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of an oil spill or leak from your offshore operations.

R: We believe we have appropriate response plans and procedures in place to deal with the environmental impact that would occur in the event of an oil spill or leak from our offshore operations. These response plans and procedures are specific to each of our affiliates, and are consistent with a global plan at the Group level. In order to minimize the risk and extent of environmental impact in the event of an oil spill or leak, TOTAL periodically reviews and regularly tests these emergency plans and procedures.

Each affiliate or operational site of TOTAL is required to have in place an emergency response plan taking into account its specific activities (e.g., drilling, production, transport) and risks. Moreover, whenever an affiliate’s activities expose it to the risk of an oil spill, it has one or more oil spill contingency plan(s) and blowout contingency plan(s) to address any uncontrolled release.

These specific response plans take into account the organization adopted at all levels (site, affiliate, Direction Générale Exploration & Production and Group level) for managing any emergency or crisis situation. They are generally designed to cover, among others, the following matters:

• listing all pertinent data and characteristics that may be useful in appraising the context (local, geographical, environmental, geological, etc., as the case may be);

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• conducting risk analysis to identify the parameters, methods and tools necessary for evaluating the situation and its probable development, together with a definition of the appropriate measures or solutions;

• detailing the actions to be taken in response to the relevant situation(s), emphasizing the initial emergency actions;

• stipulating the interfaces and liaisons required for the specific situation(s) under consideration; and

• identifying the emergency/backup means and resources potentially necessary, and how they are to be mobilized.

At the Group level, we have set up the alert scheme PARAPOL (Plan to mobilize Resources Against Pollution) to facilitate crisis management and assist with mobilizing resources in case of pollution. PARAPOL is made available to our affiliates and its main aim is to facilitate access to both internal and external response resources in the event of a pollution of marine, coastal or inland waters, without geographical restriction. The PARAPOL Procedure describes the organization of the emergency response team’s efforts, which is led by a PARAPOL Coordinator who manages or monitors the incident in order to access additional resources, both in terms of equipment and response experts. PARAPOL allows the mobilization of Group experts previously cleared to provide specific assistance to emergency response teams.

In response to the Macondo deepwater well blowout in the Gulf of Mexico, we have set up three internal task forces:

• One task force is dealing with the safety of deep-offshore drilling operations (well architecture, cementing, blow-out preventers design, operation and testing, casing equipment, procedures, prevention plans, training courses for personnel based on recent industry severe incidents).

• A second task force, in conjunction with the Global Industry Response Group (GIRG) set up by the International Association of Oil & Gas Producers (OGP), is addressing the issue of deep-offshore oil capture and containment operations in the event of a release in deep-offshore environments. In addition, we are a member of the Coordination Group and other working groups of GIRG, which focus on prevention (well engineering design and equipment and operating procedures) and intervention and response (capping, containment and oil spill response procedures).

• A third task force is reviewing our

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oil spill contingency plans to ensure proper evaluation of the potential consequences of a major accidental offshore pollution caused, in particular, by the subsea blowout of a deep-water well. Although current industry spill response technologies have proved globally efficient, we are very attentive to technical evolutions, including those recently used in the Gulf of Mexico, such as subsea injection of dispersant. We are studying these with our peers within the framework of the Oil Spill Response subgroup of GIRG and the International Petroleum Industry Environmental Conservation Association (IPIECA).

These task forces are still active, notably as the final conclusions concerning the Macondo incident are not yet available and as certain R & D programs will last for more than one year.

Furthermore, TOTAL and its affiliates are currently registered with certain external oil spill cooperatives able to provide expertise, resources and equipment in all geographic areas where TOTAL conducts its activities, including in particular: Oil Spill Response (www.oilspillresponse.com); CEDRE (www.cedre.fr); and Clean Caribbean and Americas (www.cleancaribbean.org).

Production by Geographic Area, page 12

3. Please confirm that no one country or field accounts for 15% or more of your production.

R: We confirm that no one country or field accounted for 15% or more of our production in 2009.

Item 4. Information on the Company, page 8

Production. page 11

4. We note your disclosure that the majority of your natural gas production is sold under long-term contracts and that certain of the contracts specify a fixed and determinable quantity of gas to be delivered. Please clarify for us how you considered the requirements of Item 1207(a)(2) of Regulation S-K.

R: The majority of our natural gas production is sold under long-term contracts. Some of our long term contracts, notably in Argentina, Indonesia, Nigeria, Norway and Qatar, specify the delivery of quantities of natural gas that may or may not be fixed and determinable. Such delivery commitments vary substantially, both in duration and in scope, from contract to contract throughout the world. For example, in some cases, contracts require delivery of natural gas on an as-needed basis, and, in other cases, contracts call for the delivery of varied amounts of natural gas over different periods of time. Given the substantial differences in our long-term commitments, we believe that quantifying these commitments over certain periods of time would not provide meaningful disclosure. As stated in our 2009 Annual Report, we expect to satisfy most

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of these obligations through the production of our proved reserves of natural gas in these regions, with, if needed, additional sourcing from spot market purchases.

Oil and Gas Acreage Tables, page 30

5. We note the table on page 30 indicates that as of December 31, 2009 you have a total of 71.4 million acres of net undeveloped acreage, which includes leases and concessions. Please tell us how you considered disclosing the minimum remaining terms of the leases and concessions included in your net undeveloped acreage. See Item 1208(b) of Regulation S-K.

R: We consider that our disclosure complies with Item 1208(b) of Regulation S-K. Our acreage is spread throughout the world and we have multiple licenses and concessions, which are often renewable, with different expiration terms in each geographic area. The majority of our licenses and concessions that may expire in 2010-2012 are exploration blocks the materiality of which is not exclusively a function of the size of the blocks. The materiality of an exploration block depends on multiple factors, including the geological characteristics of the underlying rock formations, the applicable regulatory requirements and possible synergies with existing operations. For these reasons and because the leases and concessions set to expire in the upcoming years are not material to the Group, we believe that providing the minimum remaining terms of such leases and concessions would not constitute meaningful disclosure.

Item 5. Operating and Financial Review and Prospects, page 62

Overview, page 62

6. We note your disclosure on page 62, which specifies that net income for 2009 includes the positive after-tax impact of prices on inventory valuation. Please enhance your discussion as to how inventory valuation impacts your reported results or include a reference to the appropriate discussion elsewhere in the filing.

R: We respectfully draw the Staff’s attention to the discussion of the impact of inventory valuation on our reported results in “Item 5. Information on the Company – Business Segment Information” on pages 67-68 of the 2009 Annual Report. As described in more detail in the referenced section of the Annual Report as well as in Note 1) to the consolidated financial statements (Accounting Policies – N) Inventories) on page F-15 of the 2009 Annual Report, we value inventories of petroleum and petrochemical products in the financial statements in accordance with IAS 2, which requires use of the FIFO (First-In, First-Out) method. As a consequence, increases or decreases in the price of oil have a significant distorting effect on our reported income and, in particular, on the results of our Downstream and Chemical segments where such inventories are held. Accordingly, the segment measure of profitability for these segments is based on a replacement cost method, conceptually similar to the LIFO (Last-In, First-Out) method,

Mr. H. Roger Schwall Securities and Exchange Commission Page 9

which management believes more accurately reflects the operating performance of the segments as it excludes the impact of oil price changes. With respect to our consolidated results, we quantify the after tax impact of oil prices on inventory valuation in the discussion of group results on page 67 of the 2009 Annual Report. In future filings, when we reference the impact of oil prices on inventory valuation, we will include a cross-reference to the appropriate discussion in “Item 5. Information on the Company – Business Segment Information” of the Annual Report.

Results 2007 - 2009, page 66

Group Results 2009 vs. 2008, page 66

7. We note you attribute the increase in your income tax provision to changes in your pre-tax income. Please tell us how you considered also providing discussion of the reasons for changes in your effective tax rate pursuant to Item 303(a)(3)(i) of Regulation S-K. In this regard, we note your effective tax rate appears to have been approximately 47%, 56%, and 49% in fiscal 2009, 2008, and 2007, respectively.

R: The decrease in the effective tax rate from 56% in 2008 to 47% in 2009 is mainly due to the fall in the portion of the Group income before tax attributable to entities with a local tax rate much higher than the French tax rate (34.43%), mainly entities from the Upstream segment. Indeed, the portion of the Upstream income before tax represents 82% in 2009 compared with 99% in 2008, with a mechanical impact on the Group effective tax rate.

A similar explanation can be given to explain the major part of the increase in the effective tax rate from 49% in 2007 to 56% in 2008. Indeed, the portion of the Upstream income before tax represents 99% in 2008 compared with 76% in 2007, with a mechanical impact on the Group effective tax rate.

In future filings, we will provide this explanation concerning the change in the effective tax rate.

Item 18. Financial Statements, page 137

Note 1. Accounting Policies, page F-8

Note G. Earnings Per Share, page F-10

8. We note your disclosure on page F-76 which specifies that you grant restricted shares to employees that are subject to continued employment. Please clarify if these unvested share awards contain non-forfeitable rights to dividends. If so, please tell us if these awards are deemed participating securities subject to the two-

Mr. H. Roger Schwall Securities and Exchange Commission Page 10

class method for computing earnings per share. Refer to paragraphs A13-A14 of IAS 33.

R: As noted on page F-67 of our 2009 Annual Report, the grant of restricted ordinary shares is subject to a two-year vesting period. During this vesting period, the beneficiary holds the right to receive restricted shares, but does not otherwise acquire any shareholder rights (e.g., right to receive dividends). The final grant of these shares is subject to a continued employment condition and, in some cases, a performance condition. Assuming the satisfaction of applicable conditions at the end of the vesting period, the beneficiary becomes the owner of restricted shares according the beneficiary all shareholder rights (including the right to receive dividends as from the final grant date) except the right to transfer such restricted shares. The beneficiary may transfer the shares at the expiration of an additional two-year mandatory holding period commencing on the final grant date.

Therefore, these awards should not be deemed participating securities subject to the two-class method for computing earnings per share.

Note 4. Business Segment Information, page F-19

D) Additional Information on Impairments, page F-29

9. We note from the disclosure that your estimated future cash flows are discounted using a real post-tax discount rate. Given the guidance provided in IAS 36 paragraph 55 that the discount rate shall be a pre-tax rate, please explain to us the specific reasons you believe use of a post-tax discount rate is appropriate, and in compliance with the accounting guidance provided in IAS 36.

R: As noted, the guidance provided in IAS 36 paragraph 55 specifies that “the discount rate shall be a pre-tax rate”. Additional guidance is provided in the basis for conclusion BCZ85, where the IASC acknowledges that “in theory, discounting post-tax cash flows at a post-tax discount rate and discounting pre-tax cash flows at a pre-tax discount rate should give the same result, as long as the pre-tax discount rate is the post-tax discount rate adjusted to reflect the specific amount and timing of the future tax cash flows”. The IASB confirmed this analysis in BC94, following comments by respondents to the December 2002 Exposure Draft. Furthermore the IASB observes in BC92 that “the definition of value in use in the previous version of IAS 36 and the associated requirements on measuring value in use were not sufficiently precise to give a definitive answer to the question of what tax attribute an entity should reflect in value in use. For example, although IAS 36 specified discounting pre-tax cash flows at a pre-tax discount rate – with the pre-tax discount rate being the post-tax discount rate adjusted to reflect the specific amount and timing of the future tax cash flows – it did not specify which tax effects the pre-tax rate should include. Arguments could be mounted for various approaches”.

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Taking this into account, TOTAL performs its impairment tests and more precisely the calculation of the value in use of its assets by using future cash flows based on the long-term plan presented to TOTAL’s management. These cash-flows are post-tax cash flows and they are discounted in a consistent manner by using a post-tax discount rate.

Oil and Gas Acreage, page 30

Supplemental Oil and Gas Information, page S-1

Preparation of Reserves Estimate, page S-1

10. We note your statement that the Geosciences Reserves Manager is the technical person responsible for preparing the reserves estimates for the Group. Please revise to provide more specific data regarding his or her qualifications beyond references to “solid background” or “strong experience.” See Item 1202(a)(7) of Regulation S-K.

R: To complement our disclosure on page S-2 of our 2009 Annual Report, the Geosciences Reserves Manager has over twenty-five years of experience in the oil & gas industry. He previously held several management positions in the Group in reservoir engineering and geosciences, and has more than ten years of experience in the field of reserves evaluation and control process. He holds an engineering degree from Ecole Nationale Supérieure de Géologie, Nancy, France, and a Ph.D in rock physics from Stanford University, California, USA. He is a member of the Society of Petroleum Engineering Oil and Gas Reserves Committee and the UNECE (United Nations Economic Commission for Europe) Expert Group on Resource Classification. We propose to include this information in our future filings.

Supplemental Oil and Gas Information, page S-1

11. We note your disclosure on page 50, which specifies that the terms of the concessions, licenses, permits and contracts governing your ownership of oil and gas interests vary from country to country. Please tell us how you classify volumes of oil that relate to royalties, in-country home taxes, or similar items where third parties may have legal ownership of such quantities and/or receive some or all of the economic interests of such volumes. As part of your response, please tell us how you considered disclosing your treatment of such volumes and how they impact your reported reserves and production volumes.

R: When royalties are payable to the owner of the mineral rights, either private or public, which is the case in the United States, or are contractually required to be paid in kind, we exclude these royalties from our calculation of SEC proved reserves.

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As far as concessions are concerned, all income taxes being paid in cash, we book our share in the contract before tax.

As far as cost oil and profit oil volumes in production sharing contracts (PSC) are concerned, as per SEC guidance, we apply the economic interest method and book them before tax.

With respect to production volumes, in all cases we book production corresponding to those reserves we have booked as SEC proved reserves.

Proved Undeveloped Reserves, page S-2

12. We note that for some of your major developments, you anticipate it may take more than five years from the time of recording proved reserves to the start of the production due to the complexity and the size of the projects. Please tell us volumes of the PUDs you currently have booked as reserves that will not begin development within five years of booking, and clarify how you determined it was appropriate to classify these as proved reserves by describing to us in more detail the “specific circumstances” that apply to these projects under Rule 4-10(31)(ii) of Regulation S-X. Refer to questions 108.01 and 131.03 through 131.06 of the Compliance and Disclosure Interpretations. You can find these interpretations at: http://www.sec.gov/divisions/corpfin/guidance/oilandgasinterp.htm.

R: Most of our approved field development projects are initiated within five years of booking with the exception of a few specific developments that currently represent approximately 350 Mboe of our PUDs. These developments located in Nigeria, Angola, Norway and Indonesia are part of a portfolio of projects with proved reserves that are primarily dedicated to the supply of LNG plants where we have participating interests. These projects were booked in conjunction with LNG projects investment decisions and will be developed over time according to a gas supply management plan that ensures that LNG trains operate at optimal capacity and contractual obligations are met.

In addition, 1.35 Bboe of proved reserves are booked on large scale projects for which development has been initiated within five years from booking but where proved reserves are expected to remain undeveloped for more than five years following project approval. These specific projects include the development of a giant field in Kazakhstan, deep offshore developments in Angola, Nigeria and the UK and development of oil sands in Canada.

Mr. H. Roger Schwall Securities and Exchange Commission Page 13

We believe that we are in compliance with the applicable requirements including the Compliance and Disclosure Interpretations referenced in the Staff’s comment no. 12, and that, in light of the facts and circumstances surrounding these specific projects, it is justified to recognize proved reserves for the following reasons:

• These projects are highly complex to develop due to a combination of factors that include, among others, the nature of the reservoir rock and fluid properties, challenging operating environments and the size of the projects. In the case of the giant field in Kazakhstan, the currently ongoing development involves the construction of an offshore production and separation hub on an artificial island, several drilling islands, onshore oil-stabilization trains and gas treatment and sulfur treatment plants. Our deep offshore development of turbiditic reservoirs in water depth greater than 800 meters involves the installation of kilometers of sub-sea production and injection systems connected through flexible risers to a floating production and storage facility. The complex nature of these projects may require more than five years to reach completion and, therefore, PUDs which remain undeveloped for more than five years following project approval.

• In addition these projects are generally designed and optimized for a given production capacity that controls the pace at which the fields are developed and wells are drilled. At production start-up, only a portion of the proved reserves are developed in order to deliver sufficient production potential to meet capacity constraints and contractual obligations. The remaining PUDs associated with the complete development plan will therefore remain undeveloped for more than five years following project approval and booking. This applies to the gas fields that are dedicated to LNG trains as mentioned above. It also applies to our oil sand development in Canada, which is based on the SAGD recovery process due to the high viscosity of the bitumen. The development involves the construction of steam generation and central processing facilities which control production capacity and the number of wells that can be operated. In this operating environment, where surface facilities have significantly longer life than SAGD well pairs, wells are drilled according to a schedule designed to maximize the use of processing facilities.

Hence, we believe that it is appropriate and in the shareholders’ best interest that we report as proved reserves the level of reserves used in connection with the project approval, assessment and investment decision, despite the fact that these proved reserves may remain undeveloped for more than five years.

In addition, we have demonstrated in recent years our ability to successfully develop and bring into production similar large-scale and complex projects, including the development of deep-offshore fields in Angola, Nigeria, Congo, HP/HT fields in UK,

Mr. H. Roger Schwall Securities and Exchange Commission Page 14

heavy oil projects in Venezuela and LNG projects in Qatar, Yemen, Nigeria and Indonesia.

Furthermore, we have already committed, and continue to commit, significant resources to these major projects with spending in 2009 that accounted for approximately one third of our total development investments in 2009.

Estimated Proved Reserves of Oil, Bitumen and Gas Reserves, page S-3

13. We note that table entitled “Changes in oil reserves” includes bitumen with crude oil and natural gas liquids. We also note the table entitled, “Changes in bitumen reserves.” As Item 1202(a)(4) asks for disclosure by product type, please tell us why you believe it is appropriate to combine bitumen with crude oil and natural gas liquids. As part of your response, please clarify whether “bitumen” refers to bitumen in its unprocessed form or as synthetic oil.

R: We confirm that “bitumen” refers to bitumen in its unprocessed form.

Prior to the amendments to SEC Rule 4-10 of Regulation S-X set forth in the “Modernization of Oil and Gas Reporting” release (SEC Release n° 33-8995) (the “Amendments”), bitumen quantities were included in our SEC proved reserves because they were extracted by traditional wells. Bitumen reserves were recorded in the “Crude oil, Condensate and Natural gas liquids” tables in our prior annual reports and are recorded in the “Changes in oil reserves” table for years 2007 and 2008 in our 2009 Annual Report (as indicated on page S-8).

As of December 31, 2009, pursuant to the Amendments, bitumen reserves for the year 2009 were presented separately (see table on page S-8).

Other Information

Net gas production, production prices, and production costs, page S-16

14. We note you present your tabular presentation depicts data for fiscal 2009. Please clarify how this presentation complies with Item 1204 of Regulation S-K, which requires such data be presented for each of the last three fiscal years. In addition, please tell us how you considered separately presenting the relevant figures for your consolidated operations and equity affiliates.

R: As Item 1204 of Regulation S-K was a new disclosure requirement for the Group for fiscal year 2009, our financial reporting systems did not permit us to furnish the required ratios prior to 2009. Based on our analysis of the revised SEC rules and our reading of FASB’s Topic 932, in the absence of an explicit requirement to disclose average sales

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prices and average costs for equity-accounted affiliates, we provided disclosure only with respect to consolidated subsidiaries.

In our future filings, we propose to present the ratios for combined consolidated operations and equity affiliates as from fiscal year 2009.

Engineering Comments

Key Information, page 1

Risk Factors, page 4

15. Please expand your risk factors to discuss the consequences of loss/breach of containment of hydrocarbons during drilling, transportation or storage.

R: As discussed in our response to the Staff’s comment no. 1, we provided extensive disclosure on the risks associated with the loss/breach of containment of hydrocarbons during drilling, transportation or storage in Item 4 of our 2009 Annual Report under the headings “Other Matters – Industrial and environmental considerations” and “Other Matters – Insurance and risk management”. In line with our historical approach to risk factor disclosure, this information was included in Item 4 (and cross-referenced in Item 3.D) in order to minimize differences in presentation between our Annual Report on Form 20-F and the annual report we prepare in France. As indicated in our response to the Staff’s comment no. 1, we intend to include in Item 3.D of our next Annual Report on Form 20-F a description of these risks substantially along the lines of our response to the Staff’s comment no. 1.

Our crude oil and natural gas reserve data are only estimates, and subsequent downward adjustments are possible. If actual production from such reserves is lower than current estimates indicate, our results of operations and financial condition would be negatively impacted, page 5

16. We note the six bullet points listing factors “which may cause our proved reserves estimates to be adjusted downward . . .” and your statement “Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time.” Please amend your document to discuss those reserve estimation items over which you have control, e.g. initial hydrocarbons in place, recovery efficiencies, initial production rates.

R: Our proved reserves figures are estimates reflecting applicable reporting regulations. They are based on existing contracts and on a set of commercial and market assumptions (e.g., oil and gas prices computed as per SEC rules). Reserves are estimated by teams of qualified, experienced, and trained earth scientists, petroleum engineers, and project engineers who rigorously review and analyze in detail all available geoscience and

Mr. H. Roger Schwall Securities and Exchange Commission Page 16

engineering data (e.g., seismic, electrical logs, cores, fluids, pressures, flow rates, facilities parameters). For proved reserves evaluation, conservative assumptions are systematically retained to estimate hydrocarbons initially in place, initial production rates or recovery efficiency. Although oil industry best practices and regulatory frameworks and guidelines are used, this process involves subjective judgments. Relying on the strict internal control process described on pages S-1 and S-2 of our Annual Report, the Group is “reasonably certain” that the proved reserves will be produced over time. However, they may be negatively impacted by a variety of factors (described in page 5 of our Annual Report) that could cause, in rare instances, such estimates to be adjusted downward in the future, or cause our actual production to be lower than our currently reported proved reserves indicate.

Middle East, page 29

17. We note your award of the Halfaya field contract by the Iraq Ministry of Oil. If you plan to claim proved reserves associated with this project, please furnish to us a detailed explanation of the contractual arrangements that support your claim to proved reserves. Address the capital you will have at risk, the contractual oil price(s) and the cost recovery and profit apportionment of derived revenue. Please tell us if you will be allowed to apply production/revenues from other areas to your Halfaya field cost recovery and profit balances.

R: A Development and Production Service Contract for the development of the Halfaya oil field was signed between Missan Oil Company of the Iraqi Ministry of Oil and a consortium including Total E&P Iraq on January 27, 2010.

The consortium’s main commitments are to develop discovered reservoirs, operate the field and achieve a production plateau of 535 kb/d for thirteen years within a certain period of time. The consortium is allowed to recover in kind the petroleum cost and to receive remuneration in kind based on a fee per barrel. Such remuneration may be reduced by a performance factor if the committed production plateau is not achieved. We therefore consider that the investments, operating costs incurred by the consortium and remuneration are at risk.

Given the characteristics of this project, we believe we will be entitled to book SEC proved reserves.

Operating and Financial Review and Prospects, page 62

Outlook, page 63

18. We note your statement “In the Upstream segment, 2010 production is expected to increase thanks to the ramp-up on projects started up in 2009 . . .” Please reconcile for us the fact that your production decreased slightly over the three years 2007-

Mr. H. Roger Schwall Securities and Exchange Commission Page 17

2009 with the statement on page 51 of your 2007 Form 20-F “. . . Total intends to pursue its strategy of profitable organic growth which the Company believes should translate to an increase in hydrocarbon production of 4% per year on average over the period 2006-2010.” We may have further comment.

R: In our 2007 Annual Report (page 51) we stated that “Total intended to pursue its strategy of profitable organic growth which the Company believed should translate to an increase in hydrocarbon production of 4% per year on average over the period 2006-2010”. This forward-looking statement was based on our management’s beliefs and assumptions at the time the statement was made and, as such, was subject to risks and uncertainties. As noted by the Staff, our production decreased slightly over the three years 2007-2009, some of the assumptions underpinning our 2007 projections having proved to be inaccurate. The difference between our prospects of growth for 2006-2010 and our actual production levels over the period 2007-2009 results primarily from the following factors, the most significant of which were beyond our ability to control or predict:

• delays in project start-ups (delays including the developments of Yemen LNG, Tahiti in the United States, Qatargas II and OML 58 in Nigeria);

• security issues in Nigeria (production from non operated onshore and offshore joint ventures decreased instead of the targeted increase);

• OPEC restrictions and lower gas demand in Europe due to the global economic crisis, which was not anticipated when our 2006 objectives were set; and

• various factors, including price effect (impact of changes in hydrocarbon prices on entitlement production – mainly in Angola due to very high prices in 2007 and 2008) and lower potential on a few fields.

We highlight that, so far in 2010, we have experienced a substantial growth in production, with production having increased by 6% during the first half 2010 as compared to the same period last year.

Supplemental Oil and Gas Information (Unaudited), page S-1

Proved undeveloped reserves, page S-2

19. We note the discussion of changes to your PUD reserves through conversion to developed status. Item 1203(b) of Regulation S-K requires the disclosure of material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves converted into proved developed reserves. Please amend your document to present also the separate figures for changes to your PUD reserves due to conversion to developed status, revisions of previous estimates,

Mr. H. Roger Schwall Securities and Exchange Commission Page 18

extensions and discoveries (drilling), improved recovery and acquisitions/divestitures.

R: In addition to our disclosure on the changes in PUD reserves (page S-2 of our Annual Report), the requested figures are set forth below. As of December 31, 2009, our combined proved undeveloped reserves of oil and gas were 4,648 Mboe as compared to 5,215 Mboe at the end of 2008. The net reduction of 568 Mboe of proved undeveloped reserves was due to the conversion of 1,144 Mboe of proved undeveloped reserves into proved developed reserves, the addition of 445 Mboe of undeveloped reserves related to extensions and discoveries, the revision of 125 Mboe of previous estimates and a net increase of 7 Mboe due to acquisitions/divestures.

In our future filings, we propose to include this additional disclosure.

20. Item 1203(c) requires a discussion of investments and progress made during the year to convert proved undeveloped reserves to proved developed reserves, including, but not limited to, capital expenditures. Please amend your document to disclose the figures for the capital you expended to develop your PUD reserves in 2009.

R: In 2009, we incurred development costs of €8.1 billion (page S-12 of our Annual Report). Of this amount, €0.6 billion was allocated to asset retirement costs. The principle component of the balance of capital expenditures was used to convert proved undeveloped reserves to proved developed reserves. We propose to include this information in our future filings.

Standardized Measure of Discounted Future Net Cash Flows (Excluding Transportation), page S-14

21. We note the exclusion of transportation in this page heading. Please explain to us your treatment of transportation costs in the calculation of the standardized measure.

R: Consistent with previous years’ disclosures, in our Standardized Measure of Discounted Future Net Cash Flows disclosure we exclude amounts related to transportation of hydrocarbon in compliance with ASC 932.

22. Please explain the procedures you used to arrive at the reserve determination prices. Include illustrations with figures that correspond to those you used for proved reserves attributed to a representative field in Africa, Europe and the US.

R: In accordance with the new SEC rule, a 12-month average price is used, unless prices are fixed by contractual arrangements. The 12-month average price is calculated as the unweighted arithmetic average of the quotations published by Platts or Argus for the first

Mr. H. Roger Schwall Securities and Exchange Commission Page 19

day of each month of the year. If the first day of the month is a non-trading day, the last trading day quotation of the preceding month is used.

Set forth below is a table showing the calculation of the main marker prices using the 12-month average price methodology:

$/bbl

Jan-09

Feb-09

Mar-09

Apr-09

May-09

Jun-09

Jul-09

Aug-09

Sep-09

Oct-09

Nov-09

Dec-09

Avg. 09

Trading day

31 Dec 08

30 Jan 09

27 Feb 09

01 Apr 09

01 May 09

01 Jun 09

01 Jul 09

31 Jul 09

01 Sep 09

01 Oct 09

30 Oct 09

01 Dec 09

BRENT - Dated Spot Platts

36.55

44.44

44.64

46.45

51.97

66.79

68.78

69.88

68.66

67.18

74.97

78.61

59.91

Jan-09

Feb-09

Mar-09

Apr-09

May-09

Jun-09

Jul-09

Aug-09

Sep-09

Oct-09

Nov-09

Dec-09

Avg. 09

Trading day

31 Dec 08

30 Jan 09

27 Feb 09

01 Apr 09

01 May 09

01 Jun 09

01 Jul 09

31 Jul 09

01 Sep 09

01 Oct 09

30 Oct 09

01 Dec 09

WTI Cushing - Platts 1st Quotation

44.61

41.70

44.76

48.38

53.19

68.35

69.28

69.21

68.28

70.56

77.04

78.30

61.14

Jan-09

Feb-09

Mar-09

Apr-09

May-09

Jun-09

Jul-09

Aug-09

Sep-09

Oct-09

Nov-09

Dec-09

Avg. 09

Trading day

31 Dec 08

30 Jan 09

27 Feb 09

01 Apr 09

30 Apr 09

01 Jun 09

01 Jul 09

31 Jul 09

01 Sep 09

01 Oct 09

30 Oct 09

01 Dec 09

DUBAI - Platts 1st Quotation

36.40

44.02

44.16

47.18

50.05

66.42

70.00

67.55

69.18

68.32

77.07

79.17

59.96

Crude prices are assessed as a differential to the Brent price (BFOE), and different methodologies can be used. The examples shown below illustrate the main methodologies.

Differential quoted: example of the Nigerian crude Bonny Light (OML 58 in Nigeria)

The differentials are quoted by Argus so the first of month pricing methodology is applied.

Jan-09

Feb-09

Mar-09

Apr-09

May-09

Jun-09

Jul-09

Aug-09

Sep-09

Oct-09

Nov-09

Dec-09

Avg. 09

$/bbl

31 Dec 08

30 Jan 09

27 Feb 09

01 Apr 09

01 May 09

01 Jun 09

01 Jul 09

31 Jul 09

01 Sep 09

01 Oct 09

30 Oct 09

01 Dec 09

BONNY LIGHT - Differential to

North Sea Dated (BFO) -

1.85

3.15

3.25

0.70

0.90

1.65

1.25

1.20

1.70

1.30

1.50

1.40

1.65

Midpoint - Argus

Differential from a quoted crude (quality bank concept): example of Tahiti in the United States

The crude oil price can be derived from another crude (quoted by Platts or Argus) using a quality differential. This is the case for U.S. crude produced by the Tahiti field. If the oil export route is the Auger/Bonito pipeline to Saint James (Bonito market), then a quality differential between Tahiti and Bonito quotations is set by the operator. In such case, a basic gravity and sulfur bank is used and, in 2009, resulted in a quality differential of [***] to be applied to the Bonito quotation (single differential value as °API and % sulfur monthly variations are marginal). So the first of month pricing methodology is applied.

$/bbl	Jan-09 31 Dec 08	Feb-09 30 Jan 09	Mar-09 27 Feb 09	Apr-09 01 Apr 09	May-09 01 May 09	Jun-09 01 Jun 09	Jul-09 01 Jul 09	Aug-09  31 Jul 09	Sep-09 01 Sep 09	Oct-09 01 Oct 09	Nov-09 30 Oct 09	Dec-09 01 Dec 09	Avg. 09
BRENT – Dated Spot Platts (i)	36.55	44.44	44.64	46.45	51.97	66.79	68.78	69.88	68.66	67.18	74.97	78.61	59.91
WTI Cushing – Platts 1st Quotation (ii)	44.61	41.7	44.76	48.38	53.19	68.35	69.28	69.21	68.28	70.56	77.04	78.3	61.14
WTI differential to BRENT (iii) = (ii) – (i)	8.07	-2.74	0.12	1.94	1.22	1.56	0.50	-0.67	-0.38	3.38	2.08	-0.31	1.23
BONITO – Pipeline – Differential to WTI – Argus (iv)	-0.90	4.80	2.15	-1.00	-1.00	-0.30	-0.70	2.00	-0.20	-1.25	-1.10	1.45	0.33
BONITO Differential to Brent (v) = (iii) + (iv)	7.17	2.06	2.27	0.94	0.22	1.26	-0.20	1.33	-0.58	2.13	0.98	1.14	1.56
[***]	[***]												[***]

Mr. H. Roger Schwall Securities and Exchange Commission Page 20

Example of a UK field

For a given UK field, the produced gas quantities are sold partially on the spot market and partially under long term contracts.

The spot reference price is calculated as the unweighted arithmetic average of the first-day-of-month quotations. If the first day of the month is a non-trading day, the last trading day quotation of the preceding month is used.

Our UK long term gas contracts usually define a quarterly or yearly price and, therefore, the first-day-of-month price will be equal to the quarterly or yearly price. As a result, the reference price is calculated as the unweighted arithmetic average of the first-day-of-month prices for each month of the year, as defined by the given contract.

23. We note (on page S-15) that the Middle East equity affiliates’ estimated future unit production cost is about €16/BOE (= €30,739 million/1,950 million BOE) while your applicable 2009 historical unit production cost (page S-11) is about €29/BOE [=€(2,800+271) million/105 million BOE]. Please illustrate this difference to us and amend your document if it is appropriate.

R: The main explanation for this difference is a portfolio effect. Our equity affiliates’ portfolio in the Middle East includes two new projects that started production during the second half of 2009 (Qatargas 2 in Qatar and Yemen LNG in Yemen). These projects have a lower unit production cost (including production taxes) than the equity affiliates’ prior portfolio in the Middle East and, as a result, their relative weight is expected to increase in the coming years. We therefore confirm the amounts disclosed both in the results of operations in 2009 and those in the standardized measure.

Mr. H. Roger Schwall Securities and Exchange Commission Page 21

Please direct any questions or comments regarding the enclosed material to the undersigned at (011)331.4744.4546 or Krystian Czerniecki of Sullivan & Cromwell LLP at (011)331.7304.5880.

Very truly yours,

/s/ Patrick de La Chevardière

Patrick de La Chevardière

Chief Financial Officer

cc:	John Cannarella
	Mark Shannon
	Ronald Winfrey
	John Lucas
	(Securities and Exchange Commission)
	Alexandre Marchal
	Dominique Bonnet
	(TOTAL S.A.)
	Krystian Czerniecki
	(Sullivan & Cromwell LLP)