Exhibit 15 a-iii

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

Pursuant to your request, we have conducted an independent reserves evaluation, completed on February 14, 2018, of the net proved oil, condensate, liquefied petroleum gas (LPG), and sales gas reserves, as of December 31, 2017, of certain properties (Table 1) that Statoil ASA (Statoil) has represented that it owns. Statoil has represented that these properties account for 100 percent, on a net equivalent barrel basis, of Statoil’s net proved reserves as of December 31, 2017, and that Statoil’s estimates of net proved reserves 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. We have reviewed information provided to us by Statoil that it represents to be Statoil’s estimates of the net reserves, as of December 31, 2017, for the same properties as those which we have independently evaluated. 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 Statoil.

Reserves estimated herein are expressed as net reserves as represented by Statoil and as estimated by DeGolyer and MacNaughton. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2017. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Statoil after deducting interests owned by others.

Estimates of oil, condensate, LPG, and sales gas 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.

Data used in this evaluation were obtained from reviews with Statoil personnel, from Statoil files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Statoil with respect to property interests, production from such properties, 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)” and also in publications of the Society of Petroleum Evaluation Engineers Monograph III and IV. 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 Statoil, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure 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.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. 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 recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those 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. This performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well-performance behavior. Analysis was performed for all well groupings (or type-curve areas) as appropriate. In the analysis of production decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

For unconventional reservoirs, characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

In certain cases, elements of the reserves estimates incorporated information based on analogy with similar reservoirs for which more complete data were available.

Gas quantities estimated herein are reported as sales gas quantities expressed at a temperature base of 15.6 degrees Celsius and a pressure base of 14.696 pounds per square inch absolute. Sales gas is defined as the total gas to be produced from the reservoirs after reduction for shrinkage from field or platform handling, separation, processing (including liquid removal), fuel usage, flaring, reinjection, pipeline losses, and onshore processing measured at the point of delivery. Gas reserves are reported as sales gas in this report. Oil and condensate

reserves estimated herein are those to be recovered by normal field separation. LPG consists of liquid quantities derived from gas processing before the point of delivery when they can be separately identified from oil and condensate. The estimates of oil, condensate, and LPG are reported in millions of barrels, where 1 barrel equals 42 United States gallons.

Definition of Reserves

Petroleum reserves estimated by Statoil and by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by Statoil and 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 known 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.

(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:

(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.

Primary Economic Assumptions

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

Statoil has represented that the provided oil, condensate, and LPG prices were based on a reference price, 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. Statoil supplied differentials by field to a Brent blend oil reference price of U.S.$54.32 per barrel and the prices were held constant thereafter. The volume-weighted average prices attributable to the proved reserves estimated by DeGolyer and MacNaughton in this report were U.S.$51.52 per barrel for oil, U.S.$48.75 per barrel for condensate, and U.S.$32.02 per barrel for LPG.

Statoil has represented that the provided gas prices were based on a reference price, 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. A significant quantity of the gas sold by Statoil is subject to contract prices, and the range of such prices is varied. Where appropriate, Statoil supplied differentials by field to a United Kingdom National Balancing Point Index of U.S.$5.72 per million Btu reference price and the prices were held constant thereafter. The volume-weighted average gas price in this report was U.S.$4.65 per million Btu.

Operating expenses, capital costs, and abandonment costs based on information provided by Statoil, were used in

estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

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, 2017, estimated reserves.

Statoil has represented that its estimated net proved reserves attributable to the reviewed properties were based on the definitions of proved reserves of the SEC. Statoil has represented that its estimates of the net proved reserves attributable to these properties, which represent 100 percent of Statoil’s reserves on a net equivalent basis, are summarized as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

DeGolyer and MacNaughton’s independent estimates of Statoil’s net proved reserves attributable to the reviewed properties were based on the definitions of proved reserves of the SEC and are summarized as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, and sales 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 Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) 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.

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.

In comparing the detailed net proved reserves estimates prepared by us and by Statoil, we have found differences, both positive and negative, resulting in an aggregate difference of 1.7 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Statoil on the properties reviewed by DeGolyer and MacNaughton and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by DeGolyer and MacNaughton.

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 Statoil. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Statoil. 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.

CERTIFICATE of QUALIFICATION

I, Regnald A Boles, 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 Statoil dated February 14, 2018, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroluem Engineering in the year 1983; 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 approximately 34 years of experience in oil and gas reservoir studies and reserves evaluations.

TABLE 1
Country
Field

Algeria
	In Amenas
	In Salah
Angola
	Acacia
	Batuque
	Bavuca
	Clochas
	Cravo
	Dalia
	Girassol
	Jasmim
	Kakocha
	Kizomba "A"
	Kizomba "B"
	Lirio
	Marimba
	Mavacola
	Mondo
	Mondo South
	Orquidea-Violeta
	Perpetua-Hortensia
	PSVM
	Rosa
	Saxi
	Zinia
Azerbaijan
	Azeri-Chirag-Gunashli
Brazil
	Peregrino
Canada
	Hebron
	Hibernia
	Hibernia South Extension Unit
	Leismer
	Terra Nova
Ireland
	Corrib
Libya
	Mabruk
	Murzuk


DeGolyer and MacNaughton

TABLE 1 - (Continued)
Country
Field
Nigeria
	Agbami
Norway
	Aasta Hansteen
	Alve
	Asgard-Midgard
	Asgard-Smorbukk
	Asgard-Smorbukk South
	Bauge
	Byrding
	Edvard Grieg
	Ekofisk
	Eldfisk
	Embla
	Enoch
	Flyndre
	Fram C-East
	Fram East
	Fram H-North
	Fram West
	Gimle
	Gina Krog
	Goliat
	Grane
	Gudrun (incl. Gudrun East)
	Gullfaks Area
	Gulltopp
	Gullveig
	Gungne
	Hanz
	Heidrun (incl. Heidrun North)
	Heimdal
	Hyme
	Ivar Aasen
	Johan Castberg
	Johan Sverdrup
	Kristin
	Kvitebjorn
	Martin Linge
	Marulk
	Mikkel
	Morvin
	Njord


DeGolyer and MacNaughton

TABLE 1 - (Continued)
Country
Field
Norway - (Continued)
	Norne
	Ormen Lange
	Oseberg
	Oseberg East
	Oseberg South
	Rhea
	Rimfaks
	Ringhorne East
	Sigyn
	Sindre
	Skarv
	Skinfaks
	Skuld
	Sleipner East
	Sleipner West
	Snadd
	Snefrid North
	Snohvit
	Snorre North
	Snorre South
	Statfjord
	Statfjord East
	Statfjord North
	Svale North
	Svalin
	Sygna
	Titan
	Tor
	Tordis Area
	Trestakk
	Troll Area
	Tune
	Tyrihans
	Urd
	Utgard
	Valemon
	Veslefrikk
	Vigdis
	Vigdis-Borg Northwest
	Vigdis East
	Vigdis Northeast
	Vilje


DeGolyer and MacNaughton

TABLE 1 - (Continued)
Country
Field
Norway - (Continued)
	Visund
	Visund South
	Volve
Russia
	Kharyaga
United Kingdom
	Alba
	Jupiter
	Mariner
United States
	Bakken
	Eagle Ford SOA
	Eagle Ford Third Party
	Green Canyon Blocks 683/726/727/770 (Caesar-Tonga)
	Green Canyon Blocks 859/903 (Heidelberg)
	Green Canyon - Stampede
	Green Canyon - Tahiti
	Marcellus - Northern District
	Marcellus - Southern District
	Marcellus SOA
	Walker Ridge - Big Foot
	Walker Ridge - Jack
	Walker Ridge - Julia
	Walker Ridge - St. Malo

	Estimated by Statoil Net Proved Reserves as of December 31, 2017
	Oil and Condensate (MMbbl)	LPG (MMbbl)	Sales Gas (Bcf)	Oil Equivalent (MMboe)

Properties Reviewed by DeGolyer and MacNaughton

Total Proved	2,302	379	15,073	5,367

Note: Gas is converted to oil equivalent using a factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent based on energy equivalency.

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2017
	Oil (MMbbl)	Condensate (MMbbl)	LPG (MMbbl)	Sales Gas (Bcf)	Oil Equivalent (MMboe)

Properties Reviewed by DeGolyer and MacNaughton

Total Proved	2,216	147	347	14,404	5,277

Note: Gas is converted to oil equivalent using a factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent based on energy equivalency.