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
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
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
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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
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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
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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.
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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
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.
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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.
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DeGolyer and MacNaughton
Regnald A. Boles, P.E.
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.
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.
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.
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