Exhibit 15.3 Report of DeGoyler and MacNaughton

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 13, 2025

Equinor ASA

Forusbeen 50

N-4035 Stavanger

Norway

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as

of December 31, 2024, 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 13, 2025. 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, 2024, 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 United States Securities and Exchange Commission (SEC). It

is our opinion that the procedures and methodologies employed by Equinor for the preparation of

its proved reserves estimates as of December 31, 2024, comply with the current requirements of

the SEC. 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, 2024, 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 remaining to be produced from these properties after December 31, 2024. Net reserves

are defined as that portion of the gross reserves attributable to the interests held by Equinor after

deducting all interests held by others.

DeGolyer and MacNaughton

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 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. A field examination was 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 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:

DeGolyer and MacNaughton

(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.

DeGolyer and MacNaughton

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.

DeGolyer and MacNaughton

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 2019” and in

Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. 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. The proved undeveloped reserves

estimates were based on opportunities identified in the plans of development provided by

Equinor.

Equinor has represented that its senior management is committed to the development

plans provided by Equinor and that Equinor has the financial capability to execute the

development plans, 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 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 performance, including production rate, reservoir pressure, and reservoir

fluid properties.

DeGolyer and MacNaughton

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 expiration of the

production licenses, as appropriate.

For the evaluation of unconventional reservoirs, a performance-based methodology

integrating the appropriate geology and petroleum engineering data was utilized for this report.

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. These analyses were performed for all well groupings (or type-curve

areas).

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 effect 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.

In the evaluation of undeveloped reserves, type-well analysis was performed using well

data from analogous wells and reservoirs for which more complete historical performance data

were available.

Data provided by Equinor from wells drilled through October 31, 2024, 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 2024. Estimated cumulative production, as of December 31, 2024, 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 reserves estimated herein consist primarily of propane and butane fractions and

are the result of low-temperature plant processing. Oil, condensate, and LPG reserves included in

DeGolyer and MacNaughton

this report are expressed in millions of barrels (106bbl). In these estimates, 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 quantities 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

quantities included 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 consist of both 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 5,612.1 cubic feet of gas per 1 barrel of oil

equivalent.

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:

Oil, Condensate, and LPG Prices

Equinor has represented that the 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 agreements. Equinor supplied differentials by

field to a Brent oil reference price of U.S.$81.17 per barrel and the prices

were held constant thereafter. The volume-weighted average prices

attributable to the estimated proved reserves over the lives of the

DeGolyer and MacNaughton

properties were U.S.$79.29 per barrel of oil, U.S.$69.45 per barrel of

condensate, and U.S.$41.19 per barrel of LPG.

Gas Prices

Equinor has also represented that the 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 agreements. 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 Title Transfer

Facility gas price index reference price of U.S.$10.81 per million Btu,

and the prices were held constant thereafter. The volume-weighted

average price attributable to the estimated proved reserves over the lives

of the properties was U.S.$7.91 per million Btu of gas.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses and future capital expenditures,

provided by Equinor and based on existing economic conditions, were

held constant for the lives of the properties. In certain cases, future

expenditures, either higher or lower than current expenditures, may have

been used because of anticipated changes in operating conditions, but no

general escalation that might result from inflation was applied.

Abandonment costs, which are those costs associated with the removal of

equipment, plugging of wells, and reclamation and restoration associated

with the abandonment, were provided by Equinor for all properties and

were not adjusted for inflation. Abandonment costs herein are inclusive

of costs incurred for existing wells and facilities as well as those for

future development associated with the proved reserves estimated herein.

Operating expenses, capital costs, and abandonment costs were

considered in determining the economic viability of the undeveloped

reserves estimated herein.

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

DeGolyer and MacNaughton

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 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.

DeGolyer and MacNaughton

Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent of

the estimated net proved oil, condensate, LPG, and sales gas reserves of certain properties in

which Equinor has represented it holds an interest.

Equinor has represented that its estimated net proved reserves attributable to the

evaluated properties were based on the definition of proved reserves of the SEC. Equinor has

represented that its estimates of the net proved reserves, as of December 31, 2024, attributable to

these properties, which represent 100 percent of Equinor’s reserves on a net equivalent basis, are

summarized as follows, expressed in millions of barrels (106bbl), billions of cubic feet (109ft3),

and millions of barrels of oil equivalent (106boe):


	Estimated by Equinor Net Proved Reserves as of December 31, 2024
	Oil (106bbl)	Condensate (106bbl)	LPG (106bbl)	Sales Gas (109ft3)	Oil Equivalent (106boe)



Total Proved	2,262.03	37.75	257.04	16,918.14	5,571.41

Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,612.1 cubic feet of gas per 1 barrel of oil equivalent.

DeGolyer and MacNaughton’s independent estimates of Equinor’s net proved reserves,

as of December 31, 2024, 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):


	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2024
	Oil (106bbl)	Condensate (106bbl)	LPG (106bbl)	Sales Gas (109ft3)	Oil Equivalent (106boe)



Total Proved	2,151.52	163.95	283.10	16,065.74	5,461.27

Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,612.1 cubic feet of gas per 1 barrel of oil equivalent.

DeGolyer and MacNaughton

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 2.0 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, 2024,

estimated reserves.

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 report has been prepared at the

request of Equinor. DeGolyer and MacNaughton has used all assumptions, data, procedures, and

methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

___________________________________

Regnald A. Boles, P.E.

Executive Vice President

DeGolyer and MacNaughton

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 an Executive Vice President with DeGolyer and MacNaughton, which firm did

prepare the report of third party addressed to Equinor dated February 13, 2025, and that I,

as Executive Vice President, was responsible for the preparation of this report of third

party.

2.That I attended Texas A&M University, and that I graduated with a Bachelor of Science

degree in Petroleum 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, the Society of Petroleum Evaluation Engineers, and the European Association

of Geoscientists & Engineers; and that I have more than 41 years of experience in oil and

gas reservoir studies and evaluations.

_________________________________

Regnald A. Boles, P.E.

Executive Vice President

DeGolyer and MacNaughton

TABLE 1

Country

Field

Algeria

In Amenas

In Salah

Angola

Acacia

Cravo

Dalia

Girassol

Kizomba A

Kizomba B

Lirio

Marte

Mondo

Orquidea-Violeta

Perpetua-Hortensia

Plutao

Rosa

Saturno

Saxi-Batuque

Venus

Zinia

Argentina

Bajo del Toro Norte

Bandurria Sur

Brazil

Bacalhau Concession

Bacalhau PSA

Peregrino

Raia

Roncador

Canada

Hebron

Hibernia

Hibernia Southern Extension

Libya

Mabruk

Murzuq

DeGolyer and MacNaughton

Norway

Aasta Hansteen

Aerfugl North

Alve

Andvare

Asgard

Bauge

Berling

Breidablikk

TABLE 1 – (Continued)

Country

Field

Norway – (Continued)

Byrding

Eirin

Enoch

Fram

Fram H-North

Fulla

Gina Krog

Goliat

Grane

Gudrun

Gullfaks Area

Gungne

Halten East

Hanz

Heidrun

Hyme

Idun North

Irpa

Ivar Aasen

Johan Castberg

Johan Sverdrup

Kristin

Kvitebjorn

Martin Linge

Marulk

Mikkel

Morvin

Munin

Njord

Norne

Ormen Lange

Ormen Lange Phase 3

DeGolyer and MacNaughton

Orn

Oseberg

Oseberg East

Oseberg South

Sigyn

Skarv

Skuld

Sleipner East

Sleipner West

Snohvit

Snorre

Statfjord

Statfjord East

Statfjord North

Svalin

Sygna

Symra

Tordis

Trestakk

TABLE 1 – (Continued)

Country

Field

Norway – (Continued)

Troll

Tune

Tyrihans

Urd

Utgard

Valemon

Verdande

Vigdis

Visund

Visund South

United Kingdom

Barnacle

Buzzard

Mariner

Rosebank

Statfjord UK

United States

APB North Non Op

APB South Non Op

Big Foot

Caesar-Tonga

DeGolyer and MacNaughton

Heidelberg

Jack

Julia

Sparta

St. Malo

Stampede

Tahiti

Titan

Vito