.

- Equinor, Annual Report on Form 20-F 2021 1

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 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

2 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 a

given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government

regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that

renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will

commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the

reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically

producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known

hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and

reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the

potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher

portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish

the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques

(including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the

reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other

evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which

the project or program was based; and (B) The project has been approved for development by all necessary

parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to

be determined. The price shall be the average price during the 12-month period prior to the ending date of the

period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month

price for each month within such period, unless prices are defined by contractual arrangements, excluding

escalations based upon future conditions.

Developed oil and gas reserves

 – Developed oil and gas reserves are reserves of any category that can be expected to

be recovered:

.

- Equinor, Annual Report on Form 20-F 2021 3

(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.

4 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

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

.

- Equinor, Annual Report on Form 20-F 2021 5

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.$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

6 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 7

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

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, 2021

Oil

(10

6

bbl)

Condensate

(10

6

bbl)

LPG

(10

6

bbl)

Sales

Gas

(10

9

ft

3

)

Oil

Equivalent

(10

6

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

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, 2021

Oil

(10

6

bbl)

Condensate

(10

6

bbl)

LPG

(10

6

bbl)

Sales

Gas

(10

9

ft

3

)

Oil

Equivalent

(10

6

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.

8 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 9

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 a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to

Equinor dated February 15, 2022, and that I, as Senior 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 38 years

of experience in oil and gas reservoir studies and evaluations.

10 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 11

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)

12 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