EXHIBIT 15.3

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 20, 2021

TOTAL E&P Holdings Russia

Tour Coupole Bureau 12D51

2, Place Jean Millier

La Défense 6

92400 Courbevoie

France

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2020, of the extent of the estimated proved oil, condensate, and gas reserves of certain fields attributable to or controlled by PAO NOVATEK (NOVATEK). The fields are either wholly held by NOVATEK or controlled by NOVATEK through its subsidiary enterprise (OOO YARGEO (YARGEO)) or through one of its joint ventures (AO ARCTIC GAS COMPANY (ARCTICGAS) or ZAO Northgas (Northgas)). TOTAL S.A. (TOTAL) has represented that it holds approximately 19.40-percent ownership interest in NOVATEK through its wholly owned subsidiary, TOTAL EP Russia. This evaluation was completed on January 20, 2021. NOVATEK has represented that its ownership interests in YARGEO, ARCTICGAS, and Northgas are 51 percent, 50 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 are reported herein as NOVATEK net reserves. At the request of TOTAL, the proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. 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 SEC filings by TOTAL.

The fields evaluated herein include the Beregovoye, East Tarkosalinskoye, East Tazovskoye, Khancheiskoye, North Khancheiskoye + Khadyryakhinskoye, North Russkoye, Dobrovolskoye, Dorogovskoye, South Khadyryakhinskoye, Sterkhovoye,

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Urengoiskoye (Olympiisky License Area), East Urengoiskoye + North Yesentinskoye (West Yaroyakhinsky License Area), Syskonsyninskoye, West Yurkarovskoye, Yurkharovskoye, and Kharbeiskoye fields held by NOVATEK; the Yarudeiskoye field held by YARGEO; the East Urengoiskoye + North Yesentinskoye (Samburgsky License Area), Samburgskoye, Urengoiskoye (Samburgsky License Area), and Yaro-Yakhinskoye fields held by ARCTICGAS; and the North Urengoisky field held by Northgas. The fields are located in the Russian Federation.

The fields evaluated are collectively referred to hereinafter as the “Russian Holdings.” TOTAL has represented that these fields account for 11 percent of TOTAL’s net proved reserves as of December 31, 2020, on a barrel of oil equivalent (boe) basis.

NOVATEK, YARGEO, ARCTICGAS, and Northgas (the Companies) have each represented that upon completion of the primary terms of their current licenses, each of the subsidiary enterprises intends to extend these licenses to the end of the economic lives of the associated fields, and that they intend to proceed accordingly with development and operations of these fields. Based on these representations and consistent with Russian law, estimates of proved reserves associated with the fields evaluated herein were not limited by the primary terms of their licenses.

Reserves estimated herein are expressed as net reserves held or controlled by NOVATEK (NOVATEK net reserves) and TOTAL’s 19.40-percent share of NOVATEK net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2020. NOVATEK net reserves are defined as that portion of the gross reserves attributable to the interests held or controlled by NOVATEK after deducting all interests held by others. NOVATEK net reserves attributable to YARGEO are presented at 100-percent interest, since NOVATEK has represented that it controls YARGEO. TOTAL’s 19.40-percent share of NOVATEK net reserves are defined as that portion of the NOVATEK net reserves attributable to TOTAL’s interest in NOVATEK.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such 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.

Information used in the preparation of this report was obtained from each of the Companies and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by each of the Companies with respect to the field interests being evaluated, production from such fields, current costs of operation

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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 was not considered necessary for the purposes of this report.

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:

(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.

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(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.

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

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(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.

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 the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and 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 (revised June 2019) Approved by the SPE Board on 25 June

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2019.” 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.

Based on the current stage of field development, production performance, the development plans provided by the Companies, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by NOVATEK.

The Companies represented that their senior management is committed to the development plan provided by the Companies and that the Companies have the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

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 OGIP.

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 as defined under the Definition of Reserves heading of this report.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

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Data provided by NOVATEK from wells drilled through December 31, 2020, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available through December 31, 2020. Cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves.

Oil reserves estimated herein are to be recovered by normal field separation and are expressed in thousands of barrels (10³bbl). In these estimates, 1 barrel equals 42 United States gallons.

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 wide-ranging light hydrocarbons (WRLH). These WRLH consist of propane and butane. 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. Condensate reserves included in this report are expressed in thousands of barrels (10³bbl). In these estimates, 1 barrel equals 42 United States gallons.

Gas quantities estimated herein are expressed as marketable gas and sales gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Sales gas is defined as the total gas to be produced from the reservoirs measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as marketable gas and sales gas. Gas quantities are expressed at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1 atmosphere (atm). Gas quantities included in this report are expressed in millions of cubic feet (10⁶ft³).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

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Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by the Companies in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

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). The Reference Price was calculated to be U.S.$41.47 per barrel. For the Companies’ holdings in the Russian Federation, the volume-weighted average oil and condensate prices over the lives of the fields were U.S.$29.04 per barrel and U.S.$25.07 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 to arrive at the price provided. All aforementioned deductions from the Reference Price were provided by NOVATEK.

Gas Prices

The Companies have represented that the gas prices were based on the Reference Price of U.S.$1.73 per thousand cubic feet (10³ft³), 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 lives of the fields was U.S.$1.45 per 10³ft³after 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, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 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 FASB 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 SEC; provided, however, that (i) estimates of 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 after initial disclosure, (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 lives 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.

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 after

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initial disclosure, 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 after initial disclosure. We believe that, since they must be developed to prevent the loss of licenses, 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.

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.

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Summary of Conclusions

The estimated NOVATEK net proved reserves, as of December 31, 2020, attributable to the Russian Holdings were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (10³bbl) and millions of cubic feet (10⁶ft³):

	NOVATEK Net Reserves
Reserves Classification	Oil (10³bbl)	Condensate (10³bbl)	Sales Gas (10⁶ft³)	Marketable Gas (10⁶ft³)

Proved Developed	204,506	465,585	19,665,681	20,489,362
Proved Undeveloped	122,942	364,441	10,528,163	10,820,151

Total Proved	327,448	830,026	30,193,844	31,309,513

The estimated TOTAL’s 19.40-percent share of NOVATEK net proved reserves, as of December 31, 2020, attributable to the Russian Holdings were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (10³bbl) and millions of cubic feet (10⁶ft³):

	TOTAL’s 19.40-percent Share of NOVATEK Net Reserves
Reserves Classification	Oil (10³bbl)	Condensate (10³bbl)	Sales Gas (10⁶ft³)	Marketable Gas (10⁶ft³)

Proved Developed	39,675	90,324	3,815,142	3,974,934
Proved Undeveloped	23,850	70,701	2,042,462	2,099,108

Total Proved	63,525	161,025	5,857,604	6,074,042

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 reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2020, estimated reserves.

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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 or in the Companies. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of TOTAL. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.

	Submitted,


	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

	/s/ Thomas D. Scott, Jr.
	Thomas D. Scott, Jr., T.P.G., C.P.G.
[Seal]	Senior Vice President
	DeGolyer and MacNaughton



	/s/ Stefan R. Krystosik
	Stefan R. Krystosik, P.E.
[Seal]	Vice President
	DeGolyer and MacNaughton

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CERTIFICATE of QUALIFICATION

I, Thomas D. Scott, Jr., Petroleum Geologist and Texas Professional Geoscientist with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to TOTAL dated January 20, 2021, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

That I attended the University of Oklahoma, and that I graduated with a Master of Science degree in Geology in the year 1988; that I am a Registered Certified Professional Geologist in the State of Texas; that I am a Registered Professional Geologist with the American Association of Petroleum Geologists; and that I have in excess of 30 years of experience in oil and gas reservoir studies and evaluations.

	/s/ Thomas D. Scott, Jr.
	Thomas D. Scott, Jr., T.P.G., C.P.G.
[Seal]	Senior Vice President
	DeGolyer and MacNaughton

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CERTIFICATE of QUALIFICATION

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

That I am a Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to TOTAL dated January 20, 2021, and that I, as Vice President, was responsible for the preparation of this report of third party.

That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2001; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 18 years of experience in oil and gas reservoir studies and evaluations.

	/s/ Stefan R. Krystosik
	Stefan R. Krystosik, P.E.
[Seal]	Vice President
	DeGolyer and MacNaughton