Equinor ASA 20F/A 2021 Annual report (foreign) (amended) | EQNR Filing

- Equinor, Annual Report on Form 20-F 2021

February 15, 2022

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, 2021, 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 15,

2022. 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, 2021, 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, 2021, 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, 2021,

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, 2021. 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.

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

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

Equinor, Annual Report on Form 20-F 2021

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

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

be recovered:

- Equinor, Annual Report on Form 20-F 2021

(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 (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 plan of development provided by Equinor.

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.

Equinor, Annual Report on Form 20-F 2021

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 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, 2021, 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 2021.

Estimated cumulative production, as of December

31, 2021, 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

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

- Equinor, Annual Report on Form 20-F 2021

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

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.$69.22 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.$67.61 per barrel

of oil, U.S.$65.02 per barrel of condensate, and

U.S.$47.17

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 United

Kingdom National Balancing Point Index

reference price of U.S.$14.01 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.$11.89 per million Btu of gas.

Operating Expenses,

Capital Costs,

and Abandonment Costs

Historical and budgeted operating expenses,

capital costs, and abandonment costs, provided by

Equinor, were

used in estimating future costs required to operate

the properties. In certain cases, future expenditures,

either

higher or lower than existing expenditures,

may have been used because of anticipated

changes in operating

Equinor, Annual Report on Form 20-F 2021

conditions,

but no general escalation that might result

from inflation was applied. Abandonment costs are those

costs associated with the removal of equipment, plugging

of wells, and reclamation and restoration associated

with the abandonment.

The abandonment costs were not escalated for

inflation and 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 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.

- Equinor, Annual Report on Form 20-F 2021

Summary of Conclusions

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, 2021, 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

bbl), billions of cubic feet (10

), and millions of barrels of oil equivalent

(10

boe):

Estimated by Equinor

Net Proved Reserves as of December 31, 2021

Oil

(10

bbl)

Condensate

(10

bbl)

LPG

(10

bbl)

Sales

Gas

(10

)

Oil

Equivalent

(10

boe)

Properties Evaluated by

DeGolyer and MacNaughton

Total Proved

2,311.1

43.6

260.7

15,380.7

5,356.0

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, 2021, 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

bbl), billions of cubic feet (10

), and millions of barrels of oil equivalent

(10

boe):

Estimated by DeGolyer and MacNaughton

Net Proved Reserves as of December 31, 2021

Oil

(10

bbl)

Condensate

(10

bbl)

LPG

(10

bbl)

Sales

Gas

(10

)

Oil

Equivalent

(10

boe)

Properties Evaluated by

DeGolyer and MacNaughton

Total Proved

2,353.0

98.2

283.2

15,448.7

5,487.2

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.

Equinor, Annual Report on Form 20-F 2021

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,

2021,

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

- Equinor, Annual Report on Form 20-F 2021

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:

That I am a Senior Vice President with DeGolyer and MacNaughton,

which firm did prepare the report of third party addressed

Equinor dated February 15, 2022, and that I, as

Senior Vice President, was responsible for the preparation

of this report of third

party.

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 38 years

of experience in oil and gas reservoir studies

and evaluations.

Equinor, Annual Report on Form 20-F 2021

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

SaxiBatuque

Venus

Zinia

Argentina

Bandurria Sur

Azerbaijan

Azeri-Chirag-Gunashli

Azeri-Chirag-Gunashli-ACE

Brazil

Bacalhau Concession

Bacalhau PSC

Peregrino

Roncador

Canada

Hebron

Hibernia

Hibernia Southern Extension

Republic of Ireland

Corrib

Libya

Murzuq

Nigeria

Agbami

- Equinor, Annual Report on Form 20-F 2021

TABLE 1

–

(Continued)

Country

Field

Norway

Aasta Hansteen

Aerfugl

Alve

Asgard

Bauge

Breidablikk

Byrding

Ekofisk

Eldfisk

Embla

Enoch

Fram

Fram H-North

Gimle

Gina Krog

Goliat

Grane

Grasel

Gudrun

Gullfaks Area

Gungne

Hanz

Heidrun

Hyme

Ivar Aasen

Johan Castberg

Johan Sverdrup

Johan Sverdrup Phase 2

Kristin

Kristin South Phase 1

Kvitebjorn

Martin Linge

Marulk

Mikkel

Morvin

Njord

Norne

Ormen Lange

Oseberg

Oseberg East

Oseberg South

Sigyn

Sindre

Skarv

Skuld

Sleipner East

Sleipner West

Snadd Outer

Snohvit

Snorre

Statfjord

TABLE 1

–

(Continued)

Country

Field

Norway –

(Continued)

Equinor, Annual Report on Form 20-F 2021

Statfjord East

Statfjord North

Svalin

Sygna

Tor

Tordis

Trestakk

Troll

Tune

Tyrihans

Urd

Utgard

Valemon

Veslefrikk

Vigdis

Visund

Visund South

Russia

Kharyaga

North Danilovsky

North Komsomolskoye

United Kingdom

Barnacle

Mariner

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

Equinor ASA (EQNR) 20-F/A2021 FY Annual report (foreign) (amended)