DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 Eas

t

Dallas, Texas 75244

February 21, 2023

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, 2022, 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, 2023. 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, 2022, 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, 2022, 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, 2022, 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, 2022. 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 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.

3

DeGolyer and MacNaughton

(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

4

DeGolyer and MacNaughton

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.

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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, 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.

6

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 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 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, 2022, 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 2022. Estimated cumulative

production, as of December 31, 2022, 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

7

DeGolyer and MacNaughton

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 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.$101.24 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.$100.30 per barrel of oil, U.S.$90.79

per barrel of condensate, and U.S.$56.23 per barrel of LPG.

Gas Prices

8

DeGolyer and MacNaughton

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.$36.35

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.$30.66

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 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

9

DeGolyer and MacNaughton

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. 

10

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, 2022,

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, 2022

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

2,211.1

36.7

280.0

14,946.1

5,191.0

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, 2022, 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, 2022

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

2227.1

84.0

289.2

15,252.1

5,318.0

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.

11

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 2.4 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, 2022, 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 letter 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, 2023, 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; that I am a member of the European

Association of Geoscientists and Engineers; and that I have in excess of

39 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

Roncador

Canada

Hebron

Hibernia

Hibernia Southern Extension

Republic of Ireland

Corrib

Libya

Mabruk

Murzuq

Nigeria

Agbami

DeGolyer and MacNaughton

TABLE 1

 –

(Continued)

Country

Field

Norway

Aasta Hansteen

Aerfugl North

Alve

Andvare

Asgard

Asterix

Bauge

Berling

Blabjorn

Breidablikk

Byrding

Enoch

Fram 

Fram H-North

Fulla

Gimle

Gina Krog

Goliat

Grane

Gudrun 

Gullfaks Area

Gungne

Halten East

Hanz

Heidrun 

Hyme

Idun North

Ivar Aasen

Johan Castberg

Johan Sverdrup

Johan Sverdrup Phase 2

Krafla

Kristin

Kristin South Phase 1

Kvitebjorn 

Lille Prinsen

Martin Linge

Marulk

Mikkel

Morvin

Njord

Norne

Ormen Lange

Ormen Lange Phase 3

Orn

Oseberg

Oseberg East

Oseberg South

Sigyn

Skarv

TABLE 1

–

(Continued)

Country

Field

DeGolyer and MacNaughton

Norway –

(Continued)

Skuld

Sleipner East

Sleipner West

Snohvit 

Snorre

Statfjord

Statfjord East

Statfjord North

Svalin

Sygna

Tordis 

Trestakk

Troll 

Tune

Tyrihans

Urd

Utgard

Valemon

Verdande

Veslefrikk

Vigdis

Visund

Visund South

United Kingdom

Barnacle

Mariner

Statfjord

United States

APB North Non-Op

APB Op

APB South Non-Op

Big Foot

Caesar-Tonga

Heidelberg

Jack

Julia

St. Malo

Stampede

Tahiti

Titan

Vito