October 21, 2016

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

By EDGAR, “CORRESP” Designation

Attention: Mr. Brad Skinner

Re:	TOTAL S.A.
	Form 20-F for the Fiscal Year Ended December 31, 2015
	Filed March 16, 2016
	SEC Letter Dated September 20, 2016
	File No. 1-10888

Dear Mr. Skinner:

Thank you for your letter dated September 20, 2016, setting forth the Staff’s comments relating to our annual report on Form 20-F for the year ended December 31, 2015, filed on March 16, 2016. 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 caption and comment from the Staff’s comment letter in bold text and have provided the Company’s response immediately following the comment.

Form 20-F for the Fiscal Year Ended December 31, 2015

Information on the Company, page 9

Business Overview, page 10

Production by Region, page 14

1. We note you have not provided separate disclosure of natural gas liquids (NGL) production. The staff considers natural gas liquids to be a separate product type under Item 1204(a) of Regulation S-K. Please revise the tables on pages 14 and 15 to disclose production by final product sold of oil/condensate and natural gas liquids as separate figures.

Mr. Brad Skinner

Securities and Exchange Commission

R: We believe our disclosure of production quantities is in compliance with Item 1204(a) of Regulation S-K. We believe separate disclosure of NGL would not be objectively or subjectively material to a reasonable investor in assessing the Company’s results or prospects, because our production of NGL production represented less than 7.5% of our total liquids production in 2015.

2. Expand your disclosure to provide the annual production volumes for each of the last three fiscal years by final product sold for each field that contains 15% or more of the Company’s proved reserves. Alternatively, expand your disclosure to clarify there are no such fields. Refer to the requirements set forth in Item 1204(a) of Regulation S-K.

R: In 2015, no field contained 15% or more of the Company’s proved reserves. In any year that any field contains 15% or more of the Company’s proved reserves, we will provide the annual production volumes for each of the last three fiscal years by final product sold for each such field. Otherwise, we will clarify that there are no such fields.

Oil and Gas Acreage, page 25

3. Please tell us the extent to which you have assigned proved undeveloped reserves to locations which are currently scheduled to be drilled after lease expiration. If your proved undeveloped reserves include material quantities of reserves relating to such locations, please expand your discussion to disclose this fact and explain the steps which would be necessary to extend the time to the expiration of such leases.

R: We have not assigned any proved undeveloped reserves to locations scheduled to be drilled after lease expiration.

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

Proved Undeveloped Reserves, page S-1

4. Please provide us with the upward or downward change due to revisions in the previous estimates of proved undeveloped reserves, on a disaggregated basis, relating to 1) new information obtained from drilling and production history, 2) economic factors, 3) improved recovery and 4) and other revisions such as changes in the prior development plans where reserves are not expected to be developed within five years since the initial disclosure of such reserves. To the extent that such unrelated changes are individually material on a disaggregated basis, please expand your disclosure to identify the individual causes and include details within an accompanying narrative to comply with the disclosure requirements pursuant to Item 1203(b) of Regulation S-K.

- 2 -

Mr. Brad Skinner

Securities and Exchange Commission

R: Using the categories enumerated above by the Staff, the revision to previous estimates of proved undeveloped reserves of +57 Mboe for the year 2015 was due to:

1) +21 Mboe due to new information obtained from drilling and production history, including primarily the drilling of additional wells in Qatar and better field behavior from Surmont in Canada, partially compensated by a revision to the Fort Hills (Canada) development plan;

2) +249 Mboe due to economic factors, including primarily a higher entitlement share (from, in particular, assets in Canada and certain other production sharing and risked service contracts) as a result of lower yearly average hydrocarbon prices, partially compensated by an economic cut-off effect (i.e., end of economic production coming earlier due to lower yearly average hydrocarbon prices) on many fields; and

4) -213 Mboe due to other revisions, including primarily a reclassification of certain projects out of proved reserves, in particular those in Venezuela, and a cancellation of several fields’ infill wells.

With respect to the Staff’s third category, improved recovery, any changes due to this category were insignificant. Therefore, in conformity with FASB ASC paragraph 932-235-50-5, we do not separately present changes due to improved recovery, but instead include such changes within revisions of previous estimates in the category new information obtained from development drilling and production history.

In response to the SEC’s request, effective with our 2016 Form 20-F, we will expand our disclosure of revisions to the previous estimates of proved undeveloped reserves to the extent that unrelated changes are individually material on a disaggregated basis in order to identify the individual causes and include details within an accompanying narrative.

5. We note you disclose a single aggregated figure for the overall net change in proved undeveloped reserves calculated from the additions related to acquisitions offset by the reductions related to divestitures. To the extent that such unrelated changes are individually material on a disaggregated basis, please expand your disclosure to identify the individual causes and include details within an accompanying narrative to comply with the disclosure requirements pursuant to Item 1203(b) of Regulation S-K.

R: The overall revision of -204 Mboe is disaggregated as follows: -228 Mboe due to divestitures (primarily, a 10% interest in Fort Hills (Canada), a 10% interest in OML 18 & OML 29 (Nigeria) and a 20% interest in assets in West of Shetland (United Kingdom)), and +24 Mboe due to acquisitions (primarily, an additional 0.66% interest in Novatek).

In response to the SEC’s request, effective with our 2016 Form 20-F, we will expand our disclosure for the overall net change in proved undeveloped reserves to the extent that unrelated changes are individually material on a disaggregated basis in order to identify the individual causes and include details within an accompanying narrative.

- 3 -

Mr. Brad Skinner

Securities and Exchange Commission

Changes in Oil, Bitumen and Gas Reserves, page S-3

6. Please provide us with the upward or downward change due to revisions in the previous estimates of total net proved reserves, on a disaggregated basis, relating to 1) new information obtained from drilling and production history, 2) economic factors, 3) improved recovery and 4) other revisions such as changes in the prior development plans where reserves are not expected to be developed within five years since the initial disclosure of such reserves. To the extent that such unrelated changes are individually significant on a disaggregated basis, please expand your disclosure to identify the individual causes and include details within an accompanying narrative to comply with the disclosure requirements pursuant to FASB ASC paragraph 932-235-50-5.

R: Using the categories enumerated above by the Staff, for consolidated subsidiaries, the revision to previous estimates of proved developed and undeveloped reserves of 196 Mboe for the year 2015 was primarily due to:

1) +291 Mboe due to new information obtained from drilling and production history;

2) +176 Mboe due to economic factors, related primarily to a higher entitlement share from, in particular, assets in Canada and certain other production sharing and risked service contracts, as a result of lower yearly average hydrocarbon prices, partially compensated by an economic cut-off effect (i.e., end of economic production coming earlier due to lower yearly average hydrocarbon prices) on many fields; and

4) -271 Mboe due other revisions, including primarily a reclassification of projects out of proved reserves.

For equity affiliates, the revision to previous estimates of proved developed and undeveloped reserves of 40 Mboe for the year 2015 was primarily due to:

1) +47 Mboe due to new information obtained from drilling and production history;

2) +35 Mboe due to economic factors, related primarily to a higher entitlement share from carry entitlement as a result of lower yearly average hydrocarbon prices; and

4) -42 Mboe due to other revisions, including primarily a reclassification of certain projects in Venezuela out of proved reserves.

With respect to the Staff’s third category, improved recovery, any changes due to this category were insignificant. Therefore, in conformity with FASB ASC paragraph 932-235-50-5, we do not separately present changes due to improved recovery, but instead include such changes within revisions of previous estimates in the category new information obtained from development drilling and production history.

In response to the SEC’s request, effective with our 2016 Form 20-F, we will expand our disclosure of revisions to the previous estimates of proved developed reserves to the extent that unrelated changes are individually significant on a disaggregated basis in order to identify the individual causes and include details within an accompanying narrative.

- 4 -

Mr. Brad Skinner

Securities and Exchange Commission

7. Expand your disclosure to provide a narrative explanation for the significant changes in total net reserves relating to each line item entry other than production. Refer to the disclosure requirements in FASB ASC paragraph 932-235-50-5.

R: The individual variations of proved developed and undeveloped reserves are mainly due to small variations on many fields. The major significant variations are listed below by region.

For consolidated subsidiaries:

• For Africa, revisions were mainly due to an economic cut-off effect partially compensated by a higher entitlement share from production sharing contracts and carry entitlements as a result of lower yearly average hydrocarbon prices. Other reasons included the debooking of Libyan onshore assets and the sale of OML18 and OML29 in Nigeria.

• For the Americas, revisions were mainly due to a higher royalty entitlement as a result of lower yearly average hydrocarbon prices, a negative revision on Fort Hills due to revision of the field development plan and a positive revision on Surmont. Other reasons included the sale of a 10% interest in Fort Hills.

• For the Middle East, revisions were mainly due to positive revisions on several Abu Dhabi and Iraqi assets, and a higher entitlement share from production sharing and risked service contracts as a result of lower yearly average hydrocarbon prices. Other reasons included the extension of the 10% stake in the Abu Dhabi Company for Onshore Petroleum Operations Ltd. (ADCO) concession for a period of 40 years, which follows a previous onshore concession.

For equity affiliates:

• For the Americas, revisions were mainly due to a reclassification of certain projects in Venezuela out of proved reserves.

• For Russia, revisions were mainly due to a positive technical revision for one of Novatek’s assets and the acquisition of an additional 0.66% of Novatek.

In response to the SEC’s request, effective with our 2016 Form 20-F, we will expand our disclosure to provide a narrative explanation for the significant changes in total net reserves relating to each line item entry other than production.

Changes in Oil Reserves, page S-5

8. We note you have not provided separate disclosure of natural gas liquids (NGL) reserves here or elsewhere in your filing on Form 20-F. The staff considers natural gas liquids to be a separate product type under Items 1202(a)(2) and 1204 of Regulation S-K. FASB ASC paragraphs 932-235-50-4 and 50-5 also require separate disclosure of natural gas liquids. Please revise the tables on pages S-5 and S-6 to separately disclose reserves and production by individual product type of oil/condensate and natural gas liquids to comply with the disclosure requirements pursuant to Items 1202(a)(2), 1204(a) of Regulation S-K and FASB ASC paragraphs 932-235-50-4 and 50-5 or explain to us why a revision is not required.

- 5 -

Mr. Brad Skinner

Securities and Exchange Commission

R: Our proved oil reserves as of December 31, 2015 were 4,495 million barrels, with NGL reserves representing less than 8.5% of such reserves. The percentage of NGL reserves was deemed not significant and, therefore, our current disclosure is in compliance with the requirements of FASB 932-235-50-4(a).

Other Information, page S-16

Net Gas Production, Production Prices and Production Costs, page S-16

9. We note you have not provided separate disclosure of the average sales price per unit of natural gas liquids produced and sold here or elsewhere in the Filing on Form 20-F. The staff considers natural gas liquids to be a separate product type under Item 1204(b)(1) of Regulation S-K. Please revise the tables on page S-16 to disclose the average sales price by final product sold of oil/condensate and natural gas liquids as separate figures.

R: We believe our disclosure of production quantities is in compliance with Item 1204(b) of Regulation S-K. We believe separate disclosure of NGL would not be objectively or subjectively material to a reasonable investor in assessing the Company’s results or prospects, as noted in our response to your comment 1.

10. Expand the disclosure of natural gas production presented as average daily rates in the tables on page S-16 to present this information as annual volumes of sales gas production for each of the last three fiscal years with disclosure by geographical area and for each country and field that contains 15% or more of your proved reserves. Refer to the requirements set forth in Item 1204(a) of Regulation S-K.

R: Effective with our 2016 Form 20-F, we will revise our disclosure of volumes of sales gas production to provide annual volumes.

Exhibit 15.3

11. The introductory portion of the reserve report prepared by DeGolyer and MacNaughton, filed as Exhibit 15.3, contains a statement indicating “the signed and bound copy of the Report should be considered the only authoritative source” of information relating to the Report. As Item 1202(a)(8) of Regulation S-K requires the report, please obtain and file a revised report to remove language that could suggest a limit upon the reliance of the report.

R: Please refer to the attached Exhibit A, which contains DeGolyer and MacNaughton’s 2015 report marked to reflect the Staff’s comments. On page 1 of Exhibit A, text has been deleted that could suggest a limit upon the reliance of the report. Effective with our 2016 Form 20-F, the report will not contain such text.

12. The reserve report on page 8 states “in connection with the Financial Accounting Standards Board and the Securities and Exchange Commission standards and regulations, it should be noted that … (iii) stable condensate and NGL are not

- 6 -

Mr. Brad Skinner

Securities and Exchange Commission

reported separately.” Please obtain and file a revised reserves report to separately disclose reserves by individual product type to comply with the disclosure requirements pursuant to FASB ASC paragraph 932-235-50-4 and Item 1202(a)(2) of Regulation S-K or explain to us why a revised report is not necessary.

R: We believe the report is in compliance with the disclosure requirements pursuant to FASB ASC paragraph 932-235-50-4 and Item 1202(a)(2) of Regulation S-K. Separate disclosure of NGL would not be objectively or subjectively material to a reasonable investor in assessing the Company’s results or prospects, as noted in our response to your comment 8.

13. The reserve report does not appear to include certain disclosures required by Item 1202(a)(8) of Regulation S-K. Specifically, we note the following:

• The proportion of the Company’s total proved reserves covered by the report. See Item 1202(a)(8)(iii) of Regulation S-K.

• The initial benchmark or reference prices by product for the reserves included in the report as part of primary economic assumptions. See Item 1202(a)(8)(v) of Regulation S-K.

• The average realized price relating to natural gas liquids reserves included in the report as part of the primary economic assumptions. See Item 1202(a)(8)(v) of Regulation S-K.

Please obtain and file a revised reserves report that includes the omitted information.

R: With respect to the Staff’s first two bullet points, please refer to pages 8 and 10 of the attached Exhibit A, which contains DeGolyer and MacNaughton’s 2015 report marked to reflect the Staff’s comments. Effective with our 2016 Form 20-F, the report will reflect these modifications

With respect to the Staff’s third bullet point, we believe the report is in compliance with the disclosure requirements pursuant to Item 1202(a)(8)(v) of Regulation S-K. Separate disclosure of NGL would not be objectively or subjectively material to a reasonable investor in assessing the Company’s results or prospects, as noted in our response to your comment 8.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

- 7 -

Mr. Brad Skinner

Securities and Exchange Commission

*            *             *

Please direct any questions or comments regarding this letter to the undersigned at +33-1-4744-4546 or Krystian Czerniecki of Sullivan & Cromwell LLP at +49-69-4272-5525.

Very truly yours,

/S/ PATRICK DE LA CHEVARDIÈRE

Patrick de La Chevardière

Chief Financial Officer

cc: John Hodgin

(Securities and Exchange Commission)

Alexandre Marchal

Andrew Zdrahal

(TOTAL S.A.)

Krystian Czerniecki

(Sullivan & Cromwell LLP)

- 8 -

October 19, 2016 Exhibit A

January 19, 2016

TOTAL E&P Holdings Russia

Tour Coupole Bureau 12D51

2, Place Jean Millier

La Défense 6

92400 Courbevoie

Ladies and Gentlemen:

Pursuant to the request of OAO Novatek (NOVATEK), we have estimated the proved oil, condensate and gas reserves, as of December 31, 2015, of certain properties owned or controlled by NOVATEK. The properties are either wholly owned by NOVATEK or controlled by NOVATEK through its subsidiary enterprise (OOO YARGEO (YARGEO)) or through one of its joint ventures (JSC ARCTIC GAS COMPANY (ARCTICGAS) or ZAO Northgas (Northgas)). TOTAL S.A. (TOTAL) has represented that it owns approximately 18.90-percent ownership interest in NOVATEK through its wholly owned subsidiary, TOTAL EP Russia. The properties are the subject of an evaluation that was completed on January 19, 2016, titled “Report as of December 31, 2015 on Reserves and Revenue owned or controlled by OAO Novatek in Certain Fields Western Siberia Russian Federation SEC Case Executive Summary Confidential” (the Report). NOVATEK has represented that its ownership interests in YARGEO, ARCTICGAS, and Northgas are 51 percent, 53.3 percent, and 50 percent in each company, respectively. Further, NOVATEK has represented that it controls YARGEO. As a result, 100 percent of the reserves of YARGEO, including the portion not owned by NOVATEK shareholders, are reported herein as NOVATEK net reserves. At the request of TOTAL, this report was prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S–K and is to be used for inclusion in certain United States Securities and Exchange Commission (SEC) filings.

The results shown herein are subject to the definitions, assumptions, explanations, qualifications, and conclusions contained in the Report. The signed and bound copy of the Report should be considered the only authoritative source of such information.

1

2

The fields evaluated herein include the East Tarkosalinskoye, Khancheiskoye, North Khancheiskoye + Khadyryakhinskoye, Dobrovolskoye, Sterkhovoye, Urengoi (Olympinsky License Area), and Yurkharovskoye fields owned by NOVATEK; the Yarudeiskoye field owned by YARGEO; the Samburgskoye, Urengoi (Samberg License Area); and Yaro-Yakhinskoye fields owned by ARCTICGAS; and the North Urengoi field owned by Northgas.

The fields evaluated are collectively referred to hereinafter as the “Russian Holdings.” NOVATEK has represented that these properties, as listed, do not include all NOVATEK fields, but account for 51 percent of NOVATEK net proved sales gas reserves as of December 31, 2015. TOTAL has represented that it owns a 18.90-percent share in NOVATEK.

The proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC.

NOVATEK, YARGEO, ARCTICGAS, and Northgas (the Companies) have each represented that the Russian Law on Subsoil provides for the extension of production licenses at the request of the license holder if there exists economic reserves upon the expiration of the primary term, provided the license holder is in material compliance with the terms of the existing license. We understand that the principal requirements for license extension are that the license holder complies with the material terms of the license and that mineral extraction has not been completed. As in the past, the Companies are required to submit to the appropriate government agency for approval, prior to production, individual field development plans based on the economic life of the field and not based on the term of the associated license. The Companies have each represented that upon completion of the primary term of its current licenses, each of the subsidiary enterprises intends to continue to extend these licenses until the end of the economic life of the associated fields, and that they intend to proceed accordingly with development and operation of these fields. Based on these representations we have included as proved reserves those volumes that are estimated to be economically producible from the fields evaluated after the expiration of the primary term of their licenses.

Reserves included herein are expressed as net reserves owned or controlled by NOVATEK (NOVATEK net reserves) and NOVATEK net reserves adjusted for

3

TOTAL’s 18.90-percent share of NOVATEK. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2015. NOVATEK net reserves are defined as that portion of the gross reserves attributable to interests owned or controlled by NOVATEK after deducting interests owned by others. NOVATEK net reserves attributable to YARGEO are included in the estimates presented at 100-percent interest, since NOVATEK has represented that it controls YARGEO. NOVATEK net reserves adjusted for TOTAL’s 18.90-percent share of NOVATEK are defined as that portion of the NOVATEK net reserves attributable to TOTAL’s interest in NOVATEK.

Data used in our estimates were obtained from each of the Companies and public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by each of the Companies with respect to ownership, production, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.

4

Estimates of ultimate recovery were obtained after applying recovery factors to OGIP and OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate reserves. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-liquid ratio behavior, was used in the estimation of reserves.

For reservoirs whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Gas reserves estimated herein are reported as separator gas and sales gas. Raw gas reserves are defined as the total quantity of gas produced from the various reservoirs of the field. Separator gas reserves were calculated from the raw gas reserves after deductions for the removal of field condensate by normal separation. Sales gas is the deliverable quantity of separator gas available for sales after deductions for various losses and usage. In addition, in certain fields evaluated herein sales gas quantities shown herein include ethane quantities that are liberated from the field condensate stream during processing and reintroduced into the gas stream for processing and sales. Since ethane quantities may be greater than fuel usage and flare losses, sales gas quantities may be greater than the separator gas volumes estimated herein. Gas quantities estimated herein are expressed at a temperature base of 20 °C and a pressure base of 1 atmosphere. Estimates of gas reserves are expressed in millions of cubic feet (10⁶ft³) and millions of cubic meters (10⁶m³).

Both stable condensate and de-ethanized condensate reserves are referred to herein as condensate reserves. Stable condensate reserves are recovered by normal separation and stabilization in the field.

De-ethanized condensate reserves include both stable condensate and natural gas liquids (NGL), or what is referred to in Russia as “shflu” or wide-range light hydrocarbons (WRLH). These WRLH consist of propane and butanes. After stable condensate removal by normal separation, additional liquids are recovered as WRLH through additional separation at reduced temperatures. Gas recovered during the de-ethanization process is reintroduced into the sales gas stream.

5

Oil reserves estimated are recovered by normal separation in the field. Estimates of condensate and oil reserves are expressed in thousands of barrels (10³bbl) and thousands of metric tons (10³mt). In these estimates, 1 barrel equals 42 United States gallons.

Definition of Reserves

Petroleum reserves estimated by us and included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

6

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

7

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

8

Our estimates of NOVATEK net proved reserves attributable to the Russian Holdings are based on the definitions of proved reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl10³bbl) and millions of cubic feet (MMcf10⁶ft³ ):

	NOVATEK Net Reserves
Reserves Classification	Oil (103bbl)		Condensate (103bbl)		Separator Gas (106ft3)		Sales Gas (106ft3)
Proved Developed		124,085		448,954		24,270,612		23,875,914
Proved Undeveloped		97,286		254,831		8,253,179		8,059,318
Total Proved		221,371		703,785		32,523,791		31,935,232

These estimates represent 100, 71, and 51 percent of the total NOVATEK net reserves of oil, condensate, and sales gas, respectively.

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4 and 932-235-50-6 through 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

In connection with the Financial Accounting Standards Board and the Securities and Exchange Commission standards and regulations, it should be noted that (i) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year, (ii) certain proved undeveloped reserves are scheduled for development more than 5 years in the future, (iii) stable condensate and NGL are not reported separately, and (iv) certain economically producible quantities of reserves beyond the primary term of the current production licenses have been classified as proved reserves in this report based on each of the Companies’ representation that the Companies have the ability to and intend to extend the applicable current production licenses to the end of the economic life of the associated fields and that each of the Companies believes with reasonable certainty that the inclusion of the reserves and revenue under extended license terms is consistent with SEC regulations. We believe it is reasonable therefore to include these quantities as SEC proved reserves for the reasons discussed herein.

9

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

We are not in a position to offer an opinion on the duration the production licenses under the Russian Law on Subsoil, but, in light of the above, believe the Companies views on the probability of license extensions to be reasonable although such view may not be confirmed by the SEC. We believe it is reasonable therefore to include these quantities as SEC proved reserves.

The Companies have each represented to us that the Russian Law on Subsoil requires that an operator develop a field according to a development plan that has been submitted to and approved by the appropriate government authority. Once approved, failure to follow the development plan is a violation of the Russian Law on Subsoil and may result in the cancellation of the operator’s production license for the field. Since the implementation of the approved development plan, including that portion that may occur more than 5 years in the future, is a requirement for maintaining the production license, we have included in certain of our estimates of SEC proved reserves those quantities associated with development activities that are part of the approved development plan and scheduled more than 5 years in the future. We believe that since they must be developed to prevent the loss of licenses that there is reasonable certainty that the reserves will be developed. We believe it is reasonable therefore to include these quantities as SEC proved reserves. The Companies have each represented to us that the development plans provided to us are in accordance with the approved development plans. We cannot render an opinion regarding the actual possibility that a license will be terminated for failure to follow approved development plans nor an opinion on how many companies have lost their licenses for not following approved development plans.

Our estimates of net proved reserves attributable to the Russian Holdings, adjusted for TOTAL’s ownership interest of 18.90 percent, are as follows, expressed in thousands of barrels (10³bblMbbl) and millions of cubic feet (10⁶ft³MMcf ):

	NOVATEK Net Reserves Adjusted for TOTAL’s 18.90-Percent Share of NOVATEK
Reserves Classification	Oil (103bbl)		Condensate (103bbl)		Separator Gas (106ft3)		Sales Gas (106ft3)
Proved Developed		23,452		84,852		4,587,145		4,512,549
Proved Undeveloped		18,389		48,164		1,559,851		1,523,210
Total Proved		41,841		133,016		6,146,996		6,035,759

10

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices, expenses, and costs, expressed in United States dollars (U.S.$):

Oil and Condensate Prices

The Companies have represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month Urals price for each month within the 12-month period prior to the end of the reporting period (the Reference Price), unless prices are defined by contractual arrangements. The Reference Price was calculated to be U.S.$53.15 per barrel. For the Companies’ holdings in the Russian Federation, the volume-weighted average oil and condensate prices over the life of the properties were U.S.$29.55 per barrel and U.S.$27.36 per barrel, respectively. The Reference Price for each field can vary based on the oil or condensate quality differential to the Urals price. Where applicable, export tariffs or value added tax, customs fees, processing fees, and transportation costs were subtracted from the Reference Price or contract price to arrive at the netback price. Any contract prices and all aforementioned deductions from the Reference Price or contract prices were provided by Novatek.

Gas Prices

The Companies have represented that the gas prices were based on a the reference Reference pricePrice, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. For the Companies’ holdings in the Russian Federation, the volume-weighted average price over the life of the properties was U.S.$1.58 per thousand cubic feet (Mcf).

11

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by the Companies, were used in estimating future expenditures required to operate the fields. In certain cases, future costs, either higher or lower than current expenditures, were used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

Estimates of oil, condensate, and gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil, condensate, and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2015, estimated oil, condensate, and gas volumes.

12

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in TOTAL. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of TOTAL. DeGolyer and MacNaughton has used all methods and procedures as it considered necessary under the circumstances to prepare this report. All assumptions, data, procedures, and methods used to prepare this report are considered by DeGolyer and MacNaughton to be appropriate for the purpose served by this report.

	Submitted,
	/s/ DeGolyer and MacNaughton
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716
	/s/ Gary L. McKenzie
	Gary L. McKenzie, P.E.
[Seal]	Senior Vice President
	DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Gary L. McKenzie, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to TOTAL dated January 19, 2016, and that I, as Senior Vice President, was responsible for the preparation of this report.

2. That I attended the U.S. Military Academy at West Point, and that I graduated with a Bachelor of Science degree in 1976; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 34 years of experience in oil and gas reservoir studies and reserves evaluations.

	/s/ Gary L. McKenzie
	Gary L. McKenzie, P.E.
[Seal]	Senior Vice President
	DeGolyer and MacNaughton