Please wait
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.
 
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
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
 
–
 
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:
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.
 
4
DeGolyer and MacNaughton
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.
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
5
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
6
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
 
7
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.
8
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
 
(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
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
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.
 
10
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
 
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.
 
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, 2024,
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,
 
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