Please wait
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.
 
2
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.
 
5
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