December 22, 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
	SEC Letter Dated December 8, 2016
	File No. 1-10888

Dear Mr. Skinner:

Thank you for your letter dated December 8, 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, and to our response letter dated October 21, 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 captions and comments from the Staff’s comment letter in bold text and have provided the Company’s response immediately following each 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 have read your response to our comment 1 indicating that NGL production represents less than 7.5% of your total liquids production in 2015. We also note you

Mr. Brad Skinner

Securities and Exchange Commission

define the term “liquids” to consist of crude oil, bitumen, condensates and NGL and have clarified the disclosure relating to production of “liquids” by region to include footnote disclosure relating to bitumen. Please expand the footnote disclosure relating to your produced liquids volumes to explain the reason for identifying NGLs as a separate liquids product type but not also providing quantitative disclosure of such volumes.

R: In response to the Staff’s comment, the Company intends to include the following footnote in its Annual Report on Form 20-F substantially in the form below, beginning with the Company’s Annual Report on Form 20-F for the year ended December 31, 2016:

Production by region

The following table sets forth the Group’s annual liquids⁽¹⁾ and natural gas production by region.

[table]

(1) Liquids consist of crude oil, bitumen, condensates and NGL. With respect to bitumen, the Group’s production in Canada consists of bitumen only, and all of the Group’s bitumen production is in Canada. With respect to NGL, the table above does not set forth separate figures for NGL because NGL production represented less than 7.5% of the Group’s total liquids production in each of the years 2014, 2015 and 2016.

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

Changes in Oil Reserves, page S-5

2. We have read your response to our comment 8 indicating that NGL reserves represent less than 8.5% of your total liquids reserves in 2015. Please modify your tabular presentation to provide footnote disclosure to explain the reason for identifying NGLs as a separate liquids product type but not also providing quantitative disclosure of such reserves.

R: As noted in our response letter dated October 21, 2016, NGL reserves represented less than 8.5% of our total oil reserves in 2015. In response to the Staff’s comment, the Company intends to include the following footnote in its Annual Report on Form 20-F substantially in the form below, beginning with the Company’s Annual Report on Form 20-F for the year ended December 31, 2016:

Changes in oil reserves

The oil reserves include crude oil, condensates and natural gas liquids⁽¹⁾ reserves.

[tables]

(1) The table does not include separate figures for NGL reserves because they represented less than 8.5% of the Group’s proved developed and undeveloped reserves in each of the years 2014, 2015 and 2016.

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Mr. Brad Skinner

Securities and Exchange Commission

Other Information, page S-16

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

3. We note your response to our comment 9 regarding the separate disclosure of the average sales price per unit of NGLs produced and sold. Please modify your tabular presentation to provide footnote disclosure clarifying that the price for “oil” represents an average aggregate price including NGLs and explain the reason for not providing a separate NGL production price.

R: In response to the Staff’s comment, the Company intends to include the following footnote in its Annual Report on Form 20-F substantially in the form below, beginning with the Company’s Annual Report on Form 20-F for the year ended December 31, 2016:

Oil ($/b)^(c)

(c) The reported price represents an average aggregate price of prices for crude oil, condensates and NGL. The table does not include separate figures for NGL production prices because the production of NGL represented less than 7.5% of the Group’s total liquids production in each of the years 2014, 2015 and 2016.

Exhibit 15.3

4. We have read your response to our comment 13 and the marked copy of the reserves report illustrating the proposed changes to the report and note the following:

• There appears to be a modification on page 1 of the reserve report which results in deleting the date on which the report was completed, a required disclosure under Item 1202(a)(8)(ii) of Regulation S-K.

• The initial benchmark or reference price for natural gas is not presented on page 10 of the revised report. This information should be presented as part of primary economic assumptions under Item 1202(a)(8)(v) of Regulation S-K.

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

R: Please refer to the attached Exhibit A, which contains DeGolyer and MacNaughton’s 2015 report marked to reflect the Staff’s comments set forth in the Staff’s comment letters dated September 20, 2016 and December 8, 2016. Effective with the Company’s Annual Report on Form 20-F for the year ended December 31, 2016, the reserves report filed in connection with the Company’s Annual Report on Form 20-F will reflect these modifications.

With respect to the first point noted in the Staff’s comment 4, please refer to page 1 of Exhibit A, which now contains the date on which the report was completed.

With respect to the second point noted in the Staff’s comment 4, please refer to page 10 of Exhibit A, which now contains the reference price for natural gas.

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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)

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December 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

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and bound copy of the Report should be considered the only authoritative source of such information.

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

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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.

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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

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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.

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:

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(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

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period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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.

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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.

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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 (10⁶ft³ MMcf):

	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

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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 of U.S.$2.01 per thousand cubic feet (Mcf), 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 Mcf per thousand cubic feet (Mcf).after value added tax, commissions and fees, and transportation costs have been subtracted from the Reference Price.

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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.

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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