DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 Eas

t

Dallas, Texas 75244

February 21, 2024

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, 2023, 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 21, 2024. 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, 2023, 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, 2023, 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, 2023, 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,

2023. 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.

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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:

3

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.

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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.

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

5

DeGolyer and MacNaughton

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 by 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.

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 the evaluation of unconventional reservoirs, a performance-based methodology

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

6

DeGolyer and MacNaughton

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.

Data provided by Equinor from wells drilled through October 31, 2023, 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 2023. Estimated cumulative production, as of

December 31, 2023, 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 this report are expressed in millions of barrels (10

6

bbl). 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 (10

9

ft

3

).

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

7

DeGolyer and MacNaughton

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.$83.27 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 properties were U.S.$80.86 per

barrel of oil, U.S.$72.70 per barrel of condensate, and U.S.$40.27

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.$13.30 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.$11.02 per million Btu of gas.

8

DeGolyer and MacNaughton

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 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 that 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. 

9

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, 2023, 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 (10

6

bbl), billions of cubic feet (10

9

ft

3

), and millions of barrels of

oil equivalent (10

6

boe):

Estimated by Equinor

Net Proved Reserves as of December 31, 2023

Oil

(10

6

bbl)

Condensate

(10

6

bbl)

LPG

(10

6

bbl)

Sales

Gas

(10

9

ft

3

)

Oil

Equivalent

(10

6

boe)

Total Proved

2,354.55

29.60

251.20

14,470.92

5,213.87

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, 2023, 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 (10

6

bbl), billions of cubic feet (10

9

ft

3

), and millions of barrels of oil

equivalent (10

6

boe):

Estimated by DeGolyer and MacNaughton

Net Proved Reserves as of December 31, 2023

Oil

(10

6

bbl)

Condensate

(10

6

bbl)

LPG

(10

6

bbl)

Sales

Gas

(10

9

ft

3

)

Oil

Equivalent

(10

6

boe)

Total Proved

2,276.39

170.23

280.27

15,104.76

5,418.35

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.

10

DeGolyer and MacNaughton

Regnald A. Boles, P.E.

 Executive Vice President

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 3.9 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, 2023,

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

DeGolyer and MacNaughton

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 21, 2024,

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

40 years of experience in oil and gas reservoir studies and evaluations.

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

Bandurria Sur

Azerbaijan

Azeri-Chirag-Gunashli

Azeri-Chirag-Gunashli-ACE

Brazil

Bacalhau Concession

Bacalhau PSA

Peregrino

Raia

Roncador

Canada

Hebron

Hibernia

Hibernia Southern Extension

Libya

Mabruk

Murzuq

Nigeria

Agbami

DeGolyer and MacNaughton

TABLE 1

 –

(Continued)

Country

Field

Norway

Aasta Hansteen

Aerfugl North

Alve

Andvare

Asgard

Bauge

Berling

Breidablikk

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

Kristin South Phase 1

Kvitebjorn

Martin Linge

Marulk

Mikkel

Morvin

Munin

Njord

Norne

Ormen Lange

Ormen Lange Phase 3

Orn

Oseberg

Oseberg East

Oseberg South

Sigyn

Skarv

Skuld

TABLE 1

–

(Continued)

Country

DeGolyer and MacNaughton

Field

Norway –

(Continued)

Sleipner East

Sleipner West

Snohvit

Snorre

Statfjord

Statfjord East

Statfjord North

Svalin

Sygna

Symra

Tordis

Trestakk

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 Op

APB South Non-Op

Big Foot

Caesar-Tonga

Heidelberg

Jack

Julia

Sparta

St. Malo

Stampede

Tahiti

Titan

Vito