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, this report of third party presents an independent evaluation, as of December 31, 2018, of the estimated net proved oil, condensate, liquefied petroleum gas (LPG), and sales gas reserves of certain properties (Table 1) in which Equinor ASA (Equinor) has represented it holds an interest. This evaluation was completed on February 14, 2019. Equinor has represented that these properties account for 100 percent, on a net equivalent barrel basis, of Equinor’s net proved reserves as of December 31, 2018, and that Equinor’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 Equinor that it represents to be Equinor’s estimates of the net reserves, as of December 31, 2018, 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 Equinor.

Reserves estimated herein are expressed as net reserves as represented by Equinor 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, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Equinor after deducting interests held by others.

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 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.

Information used in the preparation of this report was obtained from Equinor. In the preparation of this report we have relied, without independent verification, upon information furnished by Equinor with respect to the property interests being evaluated, 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. Field examinations of the properties were not considered necessary for the purposes of this report.

Definition of Reserves

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

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 (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.

Based on the current stage of field development, production performance, the development plans provided by Equinor, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

Equinor has represented that its senior management is committed to the development plan provided by Equinor and that Equinor has 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, 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 and OGIP.

For those fields where the volumetric method was applied, estimates of ultimate recovery were obtained after applying recovery factors to OOIP and 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 reservoirs, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir pressure and reservoir fluid properties.

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-curve 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 or to the limit of 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. This performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis. 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. 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, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

Data provided by Equinor from wells drilled through December 31, 2018, 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 for certain properties only through October 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. LPG consist 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 (10⁶bbl) , where 1 barrel equals 42 United States gallons.

Gas quantities estimated herein are expressed as sales gas. 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 estimated herein are reported as sales gas. Gas reserves estimated herein are expressed at a temperature base of 15.6 degrees Celsius (°C) and at a pressure base of 14.696 pounds per square inch absolute (psia). Gas reserves presented in this report are expressed in billions of cubic feet (10⁹ft³).

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 includes 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. The gas quantities estimated herein include associated and nonassociated gas reserves.

At the request of Equinor, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Equinor.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by Equinor 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:

Equinor has represented that the oil, condensate, and LPG prices provided for this study were based on a 12-month average price (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. Equinor supplied differentials by field to a Brent oil reference price of U.S.$71.59 per barrel and the prices were held constant thereafter. The volume-weighted average prices attributable to the proved reserves estimated in this report were U.S.$67.99 per barrel for oil, U.S.$67.42 per barrel for condensate, and U.S.$39.81 per barrel for LPG.

Equinor has also represented that the gas prices provided for this study 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 Equinor is subject to contract prices, and the range of such prices is varied. Where appropriate, Equinor supplied differentials by field to a United Kingdom National Balancing Point Index of U.S.$9.73 per million Btu reference price and the prices were held constant thereafter. The volume-weighted average gas price in this report was U.S.$6.19 per million Btu.

Operating expenses, capital costs, and abandonment costs, based on information provided by Equinor, were used in estimating future costs required to operate the properties. Abandonment costs are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. 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.

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 SEC; 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.

Summary of Conclusions

DeGolyer and MacNaughton’s independent estimates of Equinor’s net proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in millions of barrels (10⁶bbl), billions of cubic feet (10⁹ft³), and millions of barrels of oil equivalent (10⁶boe):

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by Equinor, differences have been found, both positive and negative, resulting in an aggregate difference of 1.4 percent when compared on the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by Equinor on the properties evaluated 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.

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, 2018, estimated reserves.

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
	Roncador
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
	Ekofisk
	Eldfisk
	Embla
	Enoch
	Fram C-East
	Fram East
	Fram H-North
	Fram West
	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
	Norne
	Ormen Lange
	Oseberg


DeGolyer and MacNaughton

TABLE 1 - (Continued)
Country
Field
Norway - (Continued)
	Oseberg East
	Oseberg South
	Rhea
	Rimfaks
	Ringhorne East
	Sigyn
	Sindre
	Skarv
	Skinfaks
	Skuld
	Sleipner East
	Sleipner West
	Snadd
	Snefrid North
	Snohvit Area
	Snorre North
	Snorre South
	Statfjord
	Statfjord East
	Statfjord 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
	Visund
	Visund South


DeGolyer and MacNaughton

TABLE 1 - (Continued)
Country
Field
Russia
	Kharyaga
United Kingdom
	Mariner
United States
	APB North Non Op
	APB Op
	APB South Op
	Bakken NOP
	Bakken OP
	Eagle Ford Non Op
	Eagle Ford Op
	Green Canyon Blocks 683/726/727/770 (Caesar-Tonga)
	Green Canyon Blocks 859/903 (Heidelberg)
	Green Canyon - Stampede
	Green Canyon - Tahiti
	Green Canyon - Titan
	Green Canyon - Vito
	Walker Ridge - Big Foot
	Walker Ridge - Jack
	Walker Ridge - Julia
	Walker Ridge - St. Malo


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 Equinor. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Equinor. DeGolyer and MacNaughton has used all asumptions, data, procedures, and methods that it considered necessary and appropriate to prepare this report.

Submitted,
/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

(SEAL)
/s/ Peter R. Laudon, P.E., P.G.
___________________________

Peter R. Laudon, P.E., P.G.
Vice President
De Golyer and MacNaughton


DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Peter R. Laudon, 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 Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Equinor dated February 14, 2019, and that I, as Vice President, was responsible for the preparation of this report of third party.

2. That I attended theUniversity of Kansas, and that I graduated with a Bachelor of Science degree in Geology in the year 1988, and that I attended the University of Missouri at Rolla, and that I graduated with both a Master of Science degree in Geology in the year 1992 and a Bachelor of Science degree in Petroleum Engineering in the year 1995; that I am a Licensed Professional Geologist and that I am a Licensed Professional Engineer in the State of Texas; that I am a member of the American Association of Petrleum Geologists, the Society of Petroleum Engineers, and the Society of Petroleum Evaluation Engineers; and that I have in excess of 23 years of experience in oil and gas reservoir studies and evaluations.

SIGNED: February 14, 2019

(SEAL)
/s/ Peter R. Laudon
___________________________

Peter R. Laudon, P.E., P.G.
Vice President
De Golyer and MacNaughton

	Estimated by Equinor Net Proved Reserves as of December 31, 2018
	Oil and Condensate (MMbbl)	LPG (MMbbl)	Sales Gas (Bcf)	Oil Equivalent (MMboe)

Properties Reviewed by DeGolyer and MacNaughton

Total Proved	2,558	393	18,094	6,175

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, 2018
	Oil (MMbbl)	Condensate (MMbbl)	LPG (MMbbl)	Sales Gas (Bcf)	Oil Equivalent (MMboe)

Properties Reviewed by DeGolyer and MacNaughton

Total Proved	2,614	158	359	17,585	6,264

Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent.